EX-99 2 a02009991.htm

For further information:
Michele Lopiccolo, VP, Investor Relations
Phone 504/576-4879, Fax 504/576-2897
 mlopicc@entergy.com

INVESTOR NEWS

Exhibit 99.1

May 4, 2009

ENTERGY REPORTS FIRST QUARTER EARNINGS

NEW ORLEANS - Entergy Corporation reported first quarter 2009 earnings of $1.20 per share on an as-reported basis and $1.29 per share on an operational basis, as shown in Table 1 below. A more detailed discussion of quarterly results begins on page 2 of this release.

Table 1: Consolidated Earnings - Reconciliation of GAAP to Non-GAAP Measures

First Quarter 2009 vs. 2008

(Per share in U.S. $)

2009

2008

Change

As-Reported Earnings

1.20

1.56

(0.36)

Less Special Items

(0.09)

-

(0.09)

Operational Earnings

1.29

1.56

(0.27)

Weather Impact

(0.02)

(0.03)

0.01

Operational Earnings Highlights for First Quarter 2009

  • Utility, Parent & Other results were lower due to higher other taxes and depreciation and amortization expenses.
  • Entergy Nuclear earnings decreased as a result of lower production due to additional planned refueling outage days and impairments recorded on decommissioning trust fund investments.
  • Entergy's Non-Nuclear Wholesale Assets results were essentially flat.

"In the current uncertain climate, we have focused significant effort on positioning the company for long-term success while weathering the current economic storm," said J. Wayne Leonard, Entergy's chairman and chief executive officer. "While we cannot predict what will come next in these times, we will be relentless in seeking value and managing risk, and we are prepared to seize opportunities that add value for our stakeholders."

  Table of Contents                                                   Page

I.

   Consolidated Results

2
II.    Utility, Parent & Other Results

3
III.    Competitive Businesses Results

4
IV.    Other Financial Performance Highlights

5
V.    Business Separation

8
VI.    Appendices
   A. Spin-Off of Non-Utility Nuclear Business

9
   B. Variance Analysis and Special Items

12

   C. Regulatory Summary

13
     D. Financial Performance Measures and
       Historical Performance Measures

18
   E. Planned Capital Expenditures

20
   F. Definitions

21
   G. GAAP to Non-GAAP Reconciliations

23
VII.    Financial Statements 26

Entergy's business highlights include the following:

Entergy will host a teleconference to discuss this release at 10 a.m. CDT on Monday, May 4, 2009, with access by telephone, 719-457-2080, confirmation code 8064872. The call and presentation slides can also be accessed via Entergy's Web site at www.entergy.com. A replay of the teleconference will be available for seven days thereafter by dialing 719-457-0820, confirmation code 8064872. The replay will also be available on Entergy's Web site at www.entergy.com.

I. Consolidated Results

Consolidated Earnings

Table 2 provides a comparative summary of consolidated earnings per share for first quarter 2009 versus 2008, including a reconciliation of GAAP as-reported earnings to non-GAAP operational earnings. Utility, Parent & Other had lower earnings due to higher other taxes and depreciation and amortization expenses. Entergy Nuclear's earnings decreased as a result of lower revenue due to lower production resulting from additional planned refueling outage days and impairments on decommissioning trust fund investments. Entergy's Non-Nuclear Wholesale Assets business reported results essentially equal to those of first quarter 2008.

Table 2: Consolidated Earnings - Reconciliation of GAAP to Non-GAAP Measures
First Quarter 2009 vs. 2008 (see appendix F for definitions of certain measures)

(Per share in U.S. $)
 

First Quarter
 

2009

2008

Change

As-Reported

Utility, Parent & Other

0.32

0.48

(0.16)

Entergy Nuclear

0.91

1.12

(0.21)

Non-Nuclear Wholesale Assets

(0.03)

(0.04)

0.01

  Consolidated As-Reported Earnings

1.20

1.56

(0.36)

Less Special Items

Utility, Parent & Other

(0.05)

-

(0.05)

Entergy Nuclear

(0.04)

-

(0.04)

Non-Nuclear Wholesale Assets

-

-

-

  Consolidated Special Items

(0.09)

-

(0.09)

Operational

Utility, Parent & Other

0.37

0.48

(0.11)

Entergy Nuclear

0.95

1.12

(0.17)

Non-Nuclear Wholesale Assets

(0.03)

(0.04)

0.01

  Consolidated Operational Earnings

1.29

1.56

(0.27)

Weather Impact

(0.02)

(0.03)

0.01

Detailed earnings variance analysis is included in appendix B-1 to this release. In addition, appendix B-2 provides details of special items shown in Table 2 above.

Consolidated Net Cash Flow Provided by Operating Activities

Entergy's net cash flow provided by operating activities in first quarter 2009 was $375 million compared to $448 million in first quarter 2008. The decrease was due primarily to:

  • net effect of hurricanes Gustav and Ike and a major Arkansas ice storm which reduced operating cash flow at the Utility by $314 million as a result of costs associated with system repairs
  • higher working capital requirements of $113 million at Utility
  • higher expenses associated with non-utility nuclear spin-off costs and dis-synergies totaling $23 million

Offsets include:

  • an increased deferred fuel contribution at the Utility in the current quarter totaling $471 million

Table 3 provides the components of net cash flow provided by operating activities contributed by each business with quarter-to-quarter comparisons.

Table 3: Consolidated Net Cash Flow Provided by Operating Activities
First Quarter 2009 vs. 2008

(U.S. $ in millions)

First Quarter

2009

2008

Change

Utility, Parent & Other

127

123

4

Entergy Nuclear

254

340

(86)

Non-Nuclear Wholesale Assets

(6)

(15)

9

     Total Net Cash Flow Provided by Operating Activities

375

448

(73)

II. Utility, Parent & Other Results

In first quarter 2009, Utility, Parent & Other had earnings of $0.32 per share on an as-reported basis and $0.37 per share on an operational basis, compared to earnings of $0.48 per share on as-reported and operational bases in first quarter 2008. Operational results for Utility, Parent & Other in first quarter 2009 reflect higher taxes other than income taxes due to the absence of the benefit associated with favorable resolution of tax audit issues that was included in results in first quarter 2008. Higher depreciation and amortization expense also contributed to lower results in the current quarter.

Electricity usage, in gigawatt-hour sales by customer segment, is included in Table 4. Current quarter sales reflect the following:

  • Residential sales in first quarter 2009, on a weather-adjusted basis, showed a 1.8 percent decrease compared to first quarter 2008, which was also a leap-year.
  • Commercial and governmental sales, on a weather-adjusted basis, decreased 1.2 percent year over year.
  • Industrial sales in the first quarter were down 13.2 percent compared to the same quarter of 2008.

The residential and commercial and governmental sales sectors reflected a decrease quarter to quarter as the continued weakening in the economy affected customer usage across these sectors. Sales in the industrial sector for first quarter 2009 decreased significantly compared to the same quarter of 2008 primarily due to a weak economic climate that worsened in the current period. Small and mid-sized industrial customers are also being negatively affected by overseas competition. Despite the lower sales volume, net revenue at the Utility was essentially flat, in part due to the fact that a significant portion of the industrial customer bill is based on a fixed charge basis that does not vary linearly with volume changes.

Table 4 provides a comparative summary of the Utility's operational performance measures.

Table 4: Utility Operational Performance Measures

First Quarter 2009 vs. 2008 (see appendix F for definitions of measures)
 

First Quarter
 

2009

2008

% Change

% Weather Adjusted

GWh billed

  Residential

7,893

8,011

-1.5%

-1.8%

  Commercial and governmental

6,756

6,807

-0.7%

-1.2%

  Industrial

8,139

9,377

-13.2%

-13.2%

  Total Retail Sales

22,788

24,195

-5.8%

-6.0%

  Wholesale

1,387

1,290

7.5%

  Total Sales

24,175

25,485

-5.1%

O&M expense

$18.51

$17.26

7.2%

Number of retail customers

  Residential

2,321,488

2,297,765

1.0%

  Commercial and governmental

343,871

341,066

0.8%

  Industrial

38,892

40,860

-4.8%

Appendix C provides information on selected pending local and federal regulatory cases.

III. Competitive Businesses Results

Entergy's competitive businesses include Entergy Nuclear and Non-Nuclear Wholesale Assets.

Entergy Nuclear

Entergy Nuclear earned $0.91 per share on an as-reported basis and $0.95 per share on an operational basis in first quarter 2009, compared to $1.12 per share on as-reported and operational bases in first quarter 2008. Entergy Nuclear's earnings decreased primarily as a result of lower revenue due to lower generation resulting from additional planned refueling outage days and lower revenue amortization for the Palisades below-market Power Purchase Agreement. Impairments recorded in the current period associated with decommissioning trust fund investments also contributed to lower earnings.

Table 5 provides a comparative summary of Entergy Nuclear's operational performance measures.

Table 5: Entergy Nuclear Operational Performance Measures

First Quarter 2009 vs. 2008 (see appendix F for definitions of measures)
 

First Quarter
 

2009

2008

% Change

Net MW in operation

4,998

4,998

-

Average realized price per MWh

$63.84

$61.47

4%

Production cost per MWh

$23.14

$19.98

16%

Non-fuel O&M expense/purchased power per MWh

$22.44

$20.20

11%

GWh billed

10,074

10,760

-6%

Capacity factor

92%

97%

-5%

Refueling outage days:

    Indian Point 2

-

7

    Indian Point 3

21

-

    Palisades

9

-

Entergy Nuclear's sold forward position is 87 percent, 66 percent, and 46 percent of planned generation at average prices per megawatt-hour of $60, $60 and $56, for 2009, 2010, and 2011, respectively. Table 6 provides capacity and generation sold forward projections for Entergy Nuclear.

Table 6: Entergy Nuclear's Capacity and Generation Projected Sold Forward

2009 through 2013 (see appendix F for definitions of measures)

 

Remainder of 2009

2010

2011

2012

2013

Energy

Planned TWh of generation

31

40

41

41

40

Percent of planned generation sold forward (a)

  Unit-contingent

47%

31%

29%

18%

12%

  Unit-contingent with availability guarantees

40%

35%

17%

7%

6%

  Firm LD

0%

0%

0%

0%

0%

  Total

87%

66%

46%

25%

18%

Average contract price per MWh (b)

$60

$60

$56

$54

$50

Capacity

Planned net MW in operation

4,998

4,998

4,998

4,998

4,998

Percent of capacity sold forward

  Bundled capacity and energy contracts

26%

26%

25%

18%

16%

  Capacity contracts

53%

34%

25%

10%

0%

  Total

79%

60%

50%

28%

16%

Average capacity contract price per kW per month

$2.3

$3.4

$3.6

$3.6

-

Blended Capacity and Energy Recap (based on revenues)

Percent of planned energy and capacity sold forward

89%

68%

46%

22%

14%

Average contract revenue per MWh (b)

$62

$62

$59

$56

$50

(a) A portion of EN's total planned generation sold forward is associated with the Vermont Yankee contract for which pricing may be adjusted.
(b) Average contract prices exclude potential payments that may be owed under the value sharing agreement with the New York Power Authority.

 

Non-Nuclear Wholesale Assets

Entergy's Non-Nuclear Wholesale Assets business results were essentially unchanged in first quarter 2009 compared to first quarter 2008 with a loss of $(0.03) per share in the current period compared to $(0.04) per share a year ago.

IV. Other Financial Performance Highlights

Earnings Guidance

Entergy is reaffirming 2009 earnings guidance in the range of $6.70 to $7.30 per share on an operational basis, assuming a business as usual operation for the full year. As-reported guidance ranges from $6.56 to $7.16 and reflects $(0.14) per share of projected dis-synergies associated with the spin-off of Entergy's non-utility nuclear business and plans to enter into a nuclear services joint venture, both discussed below and in Appendix A. Guidance for 2009 does not include a special item for expenses, which were incurred beginning in 2008 and continuing in first quarter 2009, anticipated in connection with the outside services provided to pursue the spin-off. Entergy has indicated that should the current economic climate and power prices on Entergy Nuclear's open position persist for the balance of 2009, earnings could approach the lower end of the guidance ranges. Year-over-year changes are shown as point estimates and are applied to 2008 actual results to compute the 2009 guidance midpoint. Because there is a range of possible outcomes associated with each earnings driver, a range is applied to the calculated guidance midpoints to produce Entergy's guidance ranges for as-reported and operational earnings. 2009 earnings guidance is detailed in Table 7 below.

Table 7: 2009 Earnings Per Share Guidance - As Reported and Operational
(Per share in U.S. $) - Prepared January 2009



Segment



Description of Drivers

2008 Earnings Per Share

Expected Change

2009
Guidance
Midpoint

2009 Guidance Range

Utility,
Parent &
Other

2008 Operational Earnings per Share

2.43

Adjustment to normalize weather

0.02

Increased net revenue due to sales growth and rate actions

0.45

Decreased O&M expense

0.25

Decreased income taxes

0.15

Accretion/other

0.15

Subtotal

2.43

1.02

3.45

Entergy
Nuclear

2008 Operational Earnings per Share

4.07

Increased net revenue due to higher pricing, lower volume

0.25

Increased O&M/RFO expense

(0.05)

Increased income taxes

(0.60)

Accretion/other

(0.02)

Subtotal

4.07

(0.42)

3.65

Non-Nuclear Wholesale Assets

2008 Operational Earnings per Share

0.01

Increased losses

(0.11)

Subtotal

0.01

(0.11)

(0.10)

Consolidated
Operational

2008 Operational Earnings per Share

6.51

0.49

7.00

6.70 - 7.30

Consolidated

2008 As-Reported Earnings per Share

6.23

As-Reported

Changes detailed above

0.49

2009 Non-Utility Nuclear spin-off dis-synergies

(0.14)

2008 Non-Utility Nuclear spin-off expenses for outside services

0.28

2009 As-Reported

6.23

0.63

6.86

6.56 - 7.16

Key assumptions supporting 2009 earnings guidance are as follows:

Utility, Parent & Other

  • Normal weather
  • Retail sales growth just under 3 percent, considering effects of 2008 hurricanes and industrial expansion; nearly flat on a normalized basis excluding hurricane effect and industrial expansion
  • Increased revenue associated with rate actions
  • Decreased non-fuel operation and maintenance expense, due to absence of Entergy Arkansas' 4th quarter 2008 charge associated with non-recovery of storm reserve and removal costs; inflation essentially offset by cost reduction initiatives
  • Decreased income taxes due to lower effective tax rate in 2009 compared to 2008
  • Accretion/other is primarily driven by carrying costs recorded on unrecovered storm costs in 2009, and lower interest expense at the Parent due to lower debt outstanding and lower interest rate on corporate revolver, partially offset by higher depreciation expense associated with capital additions

Entergy Nuclear

  • 41 TWh of total output, reflecting an approximate 93 percent capacity factor, including 30 day refueling outages at Pilgrim and Palisades and 38 days at Indian Point 3 in Spring 2009
  • 86 percent of energy sold under existing contracts; 14 percent sold into the spot market
  • $61/MWh average energy contract price; $58/MWh average unsold energy price based on published market prices at the end of 2008
  • Palisades below-market PPA revenue amortization of $53 million in 2009, down from $76 million in 2008
  • Non-fuel O&M/refueling outage expense growth of approximately 2 percent
  • Increased income taxes due to higher effective tax rate in 2009 compared to 2008

Non-Nuclear Wholesale Assets

  • Increased losses associated with a business that targets a break-even operation

Share Repurchase Program

  • 2009 average fully diluted shares outstanding of approximately 194 million (including effect of equity units conversion)

Effective Income Tax Rate

  • 2009 assumes an overall effective income tax rate of 37 percent

Earnings guidance for 2009 should be considered in association with earnings sensitivities as shown in Table 8. These sensitivities illustrate the estimated change in operational earnings resulting from changes in various revenue and expense drivers. Utility sales are expected to be the most significant variable for 2009 results for Utility, Parent & Other. At Entergy Nuclear, energy prices are expected to be the most significant driver of results in 2009. Estimated annual impacts shown in Table 8 are intended to be indicative rather than precise guidance.

Table 8: 2009 Earnings Sensitivities

(Per share in U.S. $)


Variable


2009 Guidance Assumption


Description of Change

Estimated
Annual Impact (c)

Utility, Parent & Other

Sales growth
  Residential
  Commercial/Governmental
  Industrial


Just under 3% total sales growth


1% change in Residential MWh sold
1% change in Comm/Govt MWh sold
1% change in Industrial MWh sold


- / + 0.05
- / + 0.04
- / + 0.02

Rate base

Growing rate base

$100 million change in rate base

- / + 0.03

Return on equity

See Appendix C

1% change in allowed ROE

- / + 0.33

Entergy Nuclear

Capacity factor

93% capacity factor

1% change in capacity factor

- / + 0.08

Energy price

14% energy unsold at $58/MWh in 2009

$10/MWh change for unsold energy

- / + 0.18

Non-fuel operation and maintenance expense

$23/MWh non-fuel operation and maintenance expense/purchased power

$1 change per MWh

- / + 0.13

Outage (lost revenue only)

93% capacity factor, including refueling outages for three northeast units

1,000 MW plant for 10 days at average portfolio energy price of $61/MWh for sold and $58/MWh for unsold volumes in 2009

- 0.04 / n/a

(c) Based on 2008 operational average fully diluted shares outstanding of approximately 196 million.

Liquidity

At the end of the first quarter, Entergy had $1.8 billion of cash and cash equivalents on hand on a consolidated basis. Entergy also has additional financing authority, subject to debt covenants, including undrawn revolving credit facility capacity of $725 million at the end of the first quarter. Entergy routinely tests the adequacy of its liquidity under various stress scenarios and believes its current liquidity position affords the desired level of financial flexibility. Entergy Corporation's revolving credit facility requires it to maintain a consolidated debt ratio of 65 percent or less of its total capitalization. Some of the utility company credit facilities also have similar covenants.

For 2009, Entergy projected consolidated net liquidity sources of approximately $2.9 billion taking into consideration its liquidity position at December 31, 2008 and other projected sources and uses of liquidity generated in 2009. Primary sources included projected undrawn revolving credit facility capacity, operating cash flow, and planned financing/refinancing activity, primarily for Entergy Texas and other Utility Operating Companies, as well as the refinancing of $500 million of Entergy Corporation Senior Notes. Uses focused on meeting debt maturities in the fourth quarter and other voluntary debt repayment (primarily pursuant to Entergy Texas Debt Assumption Agreement and for revolving credit facilities), equity units conversion of $500 million debt to equity, as well as capital expenditures, dividend payments and share repurchases.

During the first quarter, Entergy Texas successfully completed a $500 million financing in January. Entergy expects there will be similar windows of opportunity to access the credit markets in 2009. In addition, higher than projected storm expenditures for the January ice storm in Arkansas and hurricanes Gustav and Ike will result in lower operating cash flow. To the extent earnings approach the lower end of the guidance range, operating cash flow could be further reduced. Taking these factors into consideration, Entergy continues to see its net liquidity sources above $2 billion, affording the desired level of financial flexibility on a consolidated basis from a liquidity perspective.

Table 9 provides a summary of liquidity sources and uses from December 31, 2008 through December 31, 2009.

Table 9: Entergy Corporation Liquidity-Sources and Uses
December 31, 2008 through December 31, 2009

(U.S. $ in billions) - Prepared January 2009

From 12/31/2008 through 12/31/2009 (d)

Cash and cash equivalents at December 31, 2008

1.9

Undrawn revolving credit facility capacity

2.6

Operating cash flow (e)

2.8

Planned financing/refinancing

2.0

   Total liquidity sources

9.3

Debt maturities/voluntary repayment

(3.3)

Capital expenditures

(2.2)

Return of capital (dividends, net share repurchases)

(0.7)

Fuel purchases, decommissioning trust, other

(0.2)

Total liquidity uses

(6.4)

   Net liquidity sources

2.9

  (d) Sources and uses are reported on a business as usual basis and do not incorporate potential spin-off debt transactions.
  (e) Assumes receipt of storm securitization proceeds for Entergy Texas and cash tax payments lower than statutory rate.

Debt Maturities

Debt maturities in 2009 include just over $500 million in the fourth quarter. In April, Entergy Arkansas entered into a new credit facility agreement through April 2010 in the amount of $88 million. Prior to expiration in May, Entergy Mississippi expects to renew its revolving credit facilities of $50 million. These facilities are generally renewed on an annual basis. The remaining credit facilities expire in 2012.

Table 10 provides details on Entergy's debt maturities.

Table 10: Entergy Corporation and Subsidiaries Debt Maturity Schedule (f)(g)

(U.S. $ in millions)

Maturities

4Q 2009

2010

2011

2012

2013+

Utility

219

457

280 (h)

236 (h)

5,546 (h)

Entergy Nuclear

22

31

31

30

96

Parent Company and
   Other Business Segments

267

275

86

3,233

-

    Total

508

763

397

3,499

5,642

(f) Long-term debt, including current portion, reported on a business as usual basis; does not incorporate potential spin-off debt transactions.
(g) Excludes $180 million long-term DOE obligation and $508 million total lease obligations for Waterford 3 and Grand Gulf.
(h) Pursuant to the jurisdictional separation of Entergy Gulf States, Entergy Texas has until December 31, 2010 to repay debt assumed under the
     debt assumption agreement including $92 million otherwise due in 2011, $64 million in 2012 and $387 million due in 2013+.

V. Business Separation

On November 3, 2007, Entergy's Board of Directors approved a plan to pursue a separation of the non-utility nuclear business from Entergy's regulated utility business through a tax-free spin-off of the non-utility nuclear business. Enexus Energy Corporation will be a new, independent publicly traded company. In addition, Entergy and Enexus intend to enter into a nuclear services joint venture, with equal ownership. EquaGen LLC has been selected as the name for the joint venture.

Progress achieved since the last quarter update and/or current status include:

  • An advisory committee of announced members of the Enexus Board has begun to meet periodically.
  • Discussions continue with regulators in Vermont and New York
    • In Vermont, all scheduled procedural matters have been completed and a decision from the Vermont Public Service Board is pending.
    • In New York, settlement discussions are ongoing per the December 2008 notification by the ALJs that the parties intended to conduct a settlement discussion.
  • Entergy and Enexus remain in a rolling readiness posture.

The state regulatory decisions and financing continue as the critical path items. The rolling readiness posture enables Entergy to execute the spin-off following receipt of regulatory approvals and once the timing is right to access the credit markets, both on acceptable terms.

Additional information on the spin-off including proposed new business structure, leadership teams, business overviews, financial aspirations, and a transaction timeline including regulatory filing status are included in Appendix A of this release.

VI. Appendices

Seven appendices are presented in this section as follows:

  • Appendix A includes information on Entergy's plan to separate the non-utility nuclear business from Entergy's regulated utility business through a tax-free spin-off of the non-utility nuclear business.
  • Appendix B includes earnings per share variance analysis and detail on special items that relate to the current quarter.
  • Appendix C provides information on selected pending local and federal regulatory cases.
  • Appendix D provides financial metrics for both current and historical periods. In addition, historical financial and operating performance metrics are included for the trailing eight quarters.
  • Appendix E provides a summary of planned capital expenditures for the next three years.
  • Appendix F provides definitions of the operational performance measures and GAAP and non-GAAP financial measures that are used in this release.
  • Appendix G provides a reconciliation of GAAP to non-GAAP financial measures used in this release.

Appendix A provides information on Entergy's planned spin-off of its non-utility nuclear business.

Appendix A: Spin-off of Non-Utility Nuclear Business

The announced spin-off of Entergy's non-utility nuclear business will establish a new independent, publicly traded company. Enexus Energy Corporation has been selected as the name of the new company. In addition, Entergy and Enexus intend to enter into a nuclear services joint venture, with equal ownership. EquaGen LLC has been selected as the name for the joint venture. Below are transaction details and other information on Entergy, Enexus and EquaGen.

New Business Structure

Once the transaction is complete, Entergy Corporation's shareholders will own 100 percent of the common equity in both Entergy and Enexus. Enexus' business is expected to be comprised of the non-utility nuclear assets, including the Pilgrim Nuclear Station in Plymouth, Mass., the James A. FitzPatrick and Indian Point Energy Center plants in Oswego and Buchanan, N.Y., respectively, the Palisades plant in Covert, Mich., and the Vermont Yankee plant in Brattleboro, Vt., and a power marketing operation. Entergy's business will be comprised of the current six regulated utility operating subsidiaries, System Energy Resources, Inc., the related services subsidiaries System Fuels, Inc., Entergy Operations, Inc. and Entergy Services, Inc., and the remaining Entergy subsidiaries. The newly created joint venture, EquaGen, is expected to operate the nuclear assets owned by Enexus. EquaGen is also expected to offer nuclear services to third parties, including decommissioning, plant relicensing and plant operations for Cooper Nuclear Station and others.

The joint venture operating structure for Enexus ensures that the core nuclear operations expertise currently in place at each of the non-utility nuclear plants will remain after the spin-off. Entergy Nuclear Operations, Inc., the current NRC-licensed operator of the non-utility nuclear plants, is expected to be wholly-owned by EquaGen and will remain the operator of the plants after the separation. Entergy Operations, Inc., the current NRC-licensed operator of Entergy's utility nuclear plants, will also remain in place as a wholly-owned subsidiary of Entergy and will continue to be the operator of the utility nuclear plants. The decision to retain the existing operators for the nuclear stations reflects Entergy's commitment to maintaining safety, security and operational excellence.

Leadership Team

The Entergy Board of Directors has approved certain elements of the leadership structure and designated individuals who will fill key board and management roles. The EquaGen Board of Managers will be comprised of equal membership from both Entergy and Enexus.

Brief Overview of Each Business

After completion of the business separation, Entergy will consist of the current six electric utility subsidiaries in four contiguous states with generating capacity of more than 22,000 megawatts and 15,000 miles of transmission lines. Entergy will be a customer service-focused electric and gas utility with a unique growth opportunity through its portfolio transformation strategy that benefits customers. The company will deliver electricity to 2.7 million customers in Arkansas, Louisiana, Mississippi, and Texas and will remain headquartered in New Orleans, La.

Enexus is expected to own nearly 5,000 megawatts of nuclear generation, most of which is located in the northeastern United States. This location has some of the highest average regional power prices in the United States both today and expected into the future through at least 2020. The company will be headquartered in Jackson, Miss.

EquaGen is expected to be owned 50 percent each by Entergy and Enexus, and expected to have operating responsibility for Enexus' nuclear fleet. As a premier nuclear operator, the joint venture will have broad nuclear experience building and operating boiling and pressurized water reactor technologies. EquaGen is expected to be uniquely positioned to grow through offerings of nuclear operating expertise, as well as ancillary nuclear services to third parties, including plant decommissioning and relicensing. The company will be headquartered in Jackson, Miss.

Financial Aspirations

The companies will continue to aspire to deliver superior value to owners as measured by total shareholder return. The companies believe top-quartile shareholder returns are achieved by growing earnings, delivering returns at or above the risk-adjusted cost of capital, maintaining credit quality and flexibility, and deploying capital in a disciplined manner, whether for new investments, share repurchases, dividends or debt retirements.

Financial aspirations through 2012 include the following:

Top-quartile total shareholder return:

  • Entergy: 6-8% annual earnings per share growth, a 70 to 75% dividend payout ratio target, and capacity for a new share repurchase program targeted at $2.5 billion, $0.5 billion of which has already been authorized by the Entergy Board of Directors, with the balance to be authorized and to commence following completion of spin-off
  • Enexus: $2 billion in earnings before interest, income taxes, depreciation and amortization and interest and dividend income (EBITDA), a non-GAAP financial measure defined in Appendix F, by 2012 (which assumes an average power price on open positions of roughly $95/MWh on existing plants or deployment of capital resulting in additional earnings potential) generating cash flow for investment which would create additional EBITDA, debt repayment capacity and/or distributions through share repurchases in the range of up to $0.5 billion to $1 billion annually

Credit quality and flexibility to manage risk and act on opportunities:

  • Entergy: investment grade credit with a lower risk profile
  • Enexus: strong merchant credit, relative to others (subject to market terms and conditions, Enexus expects to execute up to $4.5 billion of debt financing)

The amount of repurchases may vary as a result of material changes in business results or capital spending or new investment opportunities. Entergy and Enexus further acknowledge that limitations presented by the current credit markets, as well as depressed power prices in markets where Enexus sells power, create implications for near-term financing plans and financial results. Should these conditions extend for a prolonged period, financial aspirations would likely be affected. At the same time, current market conditions also create potential capital deployment opportunities for companies with ample liquidity which in turn creates opportunity to grow EBITDA.

2012 aspirations can be considered in association with financial sensitivities as shown in Table 11. These sensitivities illustrate the estimated change in aspiration resulting from changes in aspiration drivers. Estimated impacts shown in Table 11 are intended to be illustrative.

Table 11: 2012 Financial Sensitivities



Aspiration



2012 Aspiration Assumption



Drivers


Estimated
Annual Impact

Entergy

(Per share in U.S. $) (i)

Earnings growth

6 - 8% earnings per share CAGR;
50% from $2.5 billion post-spin share
repurchase program and balance from Utility organic growth

 

1% sales growth
$100 million/year investment in service
1% change in allowed ROE
1% change in non-fuel operation and
maintenance expense
$100 million change in debt
$500 million share repurchase post-spin

- / + 0.11
+ 0.03
- / + 0.33
- / + 0.06

- / + 0.02
+0.12 - 0.15

Enexus

(EBITDA in U.S. $; millions)

EBITDA

$2 billion EBITDA

+0 - 1,500 Btu/KWh heat rate expansion
+$0 - 30/ton CO2
+$0 - 4/kW-mo. capacity price
- / + $0 - 2/MMBtu change in gas price

Up to 400
Up to 600
Up to 200
Down/Up to 600

$0.5 - $1 billion annual share repurchase, debt repayment and/or investment capacity

$1 billion investment, assuming 40-year life and 13% weighted average cost of capital

+ 200

(i) Based on estimated 2009 average fully diluted shares outstanding of approximately 194 million.

Transaction Timing

The state regulatory decisions and financing continue as the critical path items. Due to the continued turmoil in the financial markets and a longer regulatory approval process than originally expected, Entergy and Enexus remain in a rolling readiness posture. This strategy enables Entergy to execute the spin-off following receipt of regulatory approvals and once the timing is right to access the credit markets, both on acceptable terms. The transaction is expected to close on a month end. The transactions are subject to various approvals, outlined in the following table. Final terms of the transactions and spin-off completion are subject to the subsequent approval of the Entergy Board of Directors. Citigroup and Goldman Sachs are serving as Entergy's financial advisors in this process.

Proceeding

Pending Regulatory Approvals - Spin-Off of Non-Utility Nuclear Business

Nuclear Regulatory Commission

The NRC approved Entergy Nuclear Operations, Inc.'s (ENO) application on July 28, 2008. The approval remains effective until July 28, 2009, at which time ENO may seek to extend the effective period.

   

Vermont Public Service Board

Request: On January 28, 2008, pursuant to 30 V.S.A. Sections 107, 108, 231 and 232, Entergy Nuclear Vermont Yankee, L.L.C. (EVY) and ENO requested approval from the Vermont Public Service Board (VPSB) for the indirect transfer of control, consent to pledge assets, guarantees and assignments of contracts, amendment to Certificate of Public Good (CPG) to reflect name change, replacement of guaranty and substitution of a credit support agreement.
Recent Activity: None
Next Steps: All scheduled procedural steps have been completed and a decision from the VPSB is now pending.
Other Background: Under Vermont law, approval requires a finding that actions promote the general good of the state. In accordance with the VPSB scheduling order, testimony has been filed and the discovery process is complete. Two days of technical hearings were held on July 29 and 30, 2008, and final reply briefs were filed on August 20, 2008. The fundamental positions of the parties remain essentially unchanged with opposition to the spin-off coming from the Department of Public Service, and support for the spin-off coming from the Vermont Utilities.

 

  

New York Public Service Commission

Request: On January 28, 2008, pursuant to New York State Public Service Law (NYPSL) Sections 69 and 70, Entergy Nuclear FitzPatrick, L.L.C. (ENFP), Entergy Nuclear Indian Point 2 and 3, L.L.C. (ENIP2 & 3), ENO and corporate affiliate Enexus (formerly referred to as NewCo and SpinCo) filed a petition with the New York Public Service Commission (NYPSC) requesting a declaratory ruling regarding corporate reorganization or in the alternative an order approving the transaction and an order approving debt financing. Petitioners also requested confirmation that the corporate reorganization will not have an impact on ENFP's, ENIP2 & 3's, and ENO's status as lightly regulated entities, given they will continue to be competitive wholesale generators.
Recent Activity: None
Next Steps: Absent a settlement, the Administrative Law Judges (ALJs) will submit a recommendation to the NYPSC with respect to the transaction.
Other Background: Entergy requested that the NYPSC consider the spin-off transaction consistent with a lightened regulatory regime for wholesale generators in New York, including owners and operators of nuclear generating facilities, under which PSL 70 review of changes in ownership is not required. Approval under Section 70 of the NYPSL requires a finding that actions are in the public interest. Three parties filed comments in response to Entergy's petition, and several other parties also requested to be added to the service list for the proceeding. In response to Entergy's petition, in an order dated May 23, 2008, the NYPSC declined to issue a declaratory ruling approving the transaction and to consider the transaction as one consistent with lightly-regulated generators under PSL 70. In its order, the NYPSC noted that these nuclear plants "are crucial to the adequacy of generation supply within New York" and as such additional proceedings were deemed necessary. The NYPSC established a 60 day discovery period, which initially expired on July 22, 2008, but was extended for a short period by the two assigned ALJs and expired on September 29, 2008. The fundamental positions of the parties remain essentially unchanged with opposition to the spin-off coming from the Attorney General of New York and Westchester County, New York. Support for the spin-off, conditioned on specific financial parameters, has come from the staff of the NYPSC. On October 23, 2008, the ALJs issued notification to all parties that from their review of the submissions, all issues of fact and policy material to the relief requested by Petitioners have been thoroughly addressed by the parties, an adequate record for decision is available to the Commission, and no further formal proceedings are warranted. On December 11, 2008, notice was provided that the parties intended to conduct a settlement discussion which to date has not yielded an acceptable agreement.

   

Federal Energy Regulatory Commission

FERC approved the ENO application on June 12, 2008. The approval remains effective for a reasonable period of time assuming the proposed transaction is not materially altered.
 


Securities and Exchange Commission


Request/Recent Activity: None
Next Steps: The SEC is expected to ultimately declare the filing effective shortly before the spin-off is consummated.
Other Background: Pursuant to Section 12 of the 34 Exchange Act, a Form 10 information statement is required to be filed to register securities with the SEC. The Form 10 is furnished in connection with the distribution by Entergy to its common shareholders of all of the shares of the common stock of Enexus. The information statement describes the distribution in detail and contains information about Enexus, its business, financial condition and operations. The Form 10 is subject to review and comments by the SEC staff and will need to be declared effective prior to the distribution. The Form 10 was initially filed on May 12, 2008, with first, second, and third amendments filed on July 31, September 12, and November 21, 2008. The SEC comments to date have related primarily to accounting and disclosure items.

Appendix B-1 provides details of first quarter 2009 vs. 2008 earnings variance analysis for "Utility, Parent & Other," "Competitive Businesses," and "Consolidated."

Appendix B-1: As-Reported Earnings Per Share Variance Analysis
First Quarter 2009 vs. 2008
(Per share in U.S. $, sorted in consolidated
column, most to least favorable)		              
 

Utility

    

Competitive

      
  Parent & Other    

Business

     Consolidated

2008 earnings

0.48

  

1.08

1.56

Interest and other charges

0.02

  

0.03

0.05

Decommissioning expense

(0.01)

  

-

(0.01)

Nuclear refueling outage expense

(0.02)

  

-

(0.02)

Depreciation/amortization expense

(0.03)

  

(0.01)

(0.04)

Other income (deductions)

0.01

  

(0.06)

(j)

(0.05)

Income taxes - other

(0.02)

  

(0.03)

(0.05)

Net revenue

0.01

  

(0.07)

(k)

(0.06)

Taxes other than income taxes

(0.07)

(l)

(0.01)

(0.08)

Other operation & maintenance expense

(0.05)

(m)

(0.05)

(n)

(0.10)

2009 earnings

0.32

  

0.88

1.20
  1. The decrease is due primarily to an impairment associated with decommissioning trust fund investments.
  2. The decrease is due primarily to lower revenues at Entergy Nuclear from lower production due to increased number of planned refueling outage days during the quarter and lower revenue amortization for the Palisades below-market Power Purchase Agreement.
  3. The increase is due primarily to the absence in the current period of the effects of a favorable resolution of a tax audit issue in first quarter 2008, which is partially offset in net revenue, and higher ad valorem and franchise taxes.
  4. The increase is due primarily to expenses recorded at the Parent for outside services to pursue the non-utility nuclear spin-off.
  5. The increase is due primarily to non-utility nuclear spin-off dis-synergy expenses incurred at Entergy Nuclear.

Appendix B-2 lists special items by business with quarter-to-quarter comparisons. Amounts are shown on both earnings per share and net income bases. Special items are those events that are less routine, are related to prior periods, or are related to discontinued businesses. Special items are included in as-reported earnings per share consistent with generally accepted accounting principles (GAAP), but are excluded from operational earnings per share. As a result, operational earnings per share is considered a non-GAAP measure.

Appendix B-2: Special Items (shown as positive / (negative) impact on earnings)

First Quarter and 2009 vs. 2008

(Per share in U.S. $)

 

First Quarter

 

2009

2008

Change

Utility, Parent & Other

   Non-Utility Nuclear spin-off expenses

(0.05)

-

(0.05)

Competitive Businesses

   Entergy Nuclear

   Non-Utility Nuclear spin-off dis-synergies

(0.04)

-

(0.04)

   Non-Nuclear Wholesale Assets

-

-

-

Total Competitive Businesses

(0.04)

-

(0.04)

Total Special Items

(0.09)

-

(0.09)

(U.S. $ in millions)

 

First Quarter

2009

2008

Change

Utility, Parent & Other

   Non-Utility Nuclear spin-off expenses

(10.6)

-

(10.6)

Competitive Businesses

   Entergy Nuclear

   Non-Utility Nuclear spin-off dis-synergies

(6.6)

-

(6.6)

   Non-Nuclear Wholesale Assets

-

-

-

Total Competitive Businesses

(6.6)

-

(6.6)

Total Special Items

(17.2)

-

(17.2)

 

 

 

 

 

Appendix C provides a summary of selected regulatory cases and events that are pending.

Appendix C: Regulatory Summary Table

Company/ Proceeding

Authorized ROE

Pending Cases/Events
Retail Regulation
Entergy Arkansas

9.9%

Recent activity: On April 23, 2009, the Arkansas Supreme Court denied EAI's petition for review of the Court of Appeals decision.
Background: On August 25, 2006, EAI filed a rate case requesting a $150 million increase based on a June 30, 2006 test year using an 11.25% ROE. The rate increase was revised to $106.5 million on rebuttal primarily to remove a plant acquisition included in the initial filing. The APSC order called for a $5.1 million rate reduction, 9.9% ROE and a hypothetical common equity level lower than EAI's actual capital structure. The base rate change was implemented August 29, 2007. EAI filed an appeal of the rate case order, following earlier denial of EAI's request for rehearing on its case. On December 17, 2008, the Arkansas Court of Appeals issued its decision, upholding almost all aspects of the APSC decision on EAI's rate case. Considering the progress of the proceeding, EAI recorded a charge associated with costs previously accumulated in EAI's storm reserve and removal costs associated with the termination of a lease that were not approved for recovery by the APSC in its rate case order. On January 5, 2009, EAI filed a petition for review before the Arkansas Supreme Court, requesting a review of the appeal decision.
Storm Cost Recovery: Recovery of 2008 extraordinary storm restoration costs commenced in January 2009. Later that month, EAI was struck by a severe ice storm with restoration cost estimates standing at $120 to $140 million. Considering the magnitude of the statewide storm damages, the Arkansas legislature passed legislation authorizing storm reserve accounting in March 2009, followed by the enactment of storm securitization legislation in April. Both pieces of legislation are effective for storms occurring on or after January 1, 2009. At the end of March, EAI filed a petition with the APSC to establish storm reserve accounting pursuant to the legislation. In the interim, the APSC approved on March 6, 2009 EAI's application for an accounting order authorizing the deferral of the operating and maintenance cost portion of the ice storm restoration costs pending their recovery. Finally, on April 1, 2009, EAI filed its earnings analysis test pursuant to the 2008 extraordinary storm recovery order indicating a $40.1 million revenue deficit and a resulting 7.9% regulatory ROE.
Background: As a result of the 2007 rate case order, EAI was required to discontinue storm reserve accounting and became subject to an annual $14.4 million budget for allowed storm recovery by the APSC. In its subsequent December 2007 consolidated order, the APSC indicated that it was open to consideration of alternative extraordinary storm restoration cost methodologies that are both fair and reasonable to rate payers and in the public interest. Considering the effects of hurricanes Gustav and Ike, compounded by other storms earlier in the year, EAI pursued extraordinary storm recovery. On December 19, 2008, the APSC approved EAI's request to defer 2008 extraordinary storm restoration costs for recovery via the Storm Damage Rider in 2009. The APSC reduced EAI's request by $4 million to allow for standard variation in storm costs from the normalized level in base rates. EAI is permitted to recover the retail portion of $22.3 million, subject to adjustments arising from storm cost audit, earnings review and other items consistent with past APSC regulatory practice. Storm-related capital costs were not included. EAI's filing proposed the underlying costs would be subject to audit and an earnings review, with any over-earnings to be applied to the deferral balance.
White Bluff Environmental Controls Project: On March 27, 2009, EAI petitioned the APSC to undertake the Environmental Controls project that will install scrubbers and low NOx burners at the co-owned White Bluff coal plant at an expected total cost of approximately $1.0 billion, with EAI's share at $631 million. EAI requested that the APSC issue an order by September 25, 2009, given EAI may be required to make significant commitments in fourth quarter 2009 in order to meet the 2013 compliance deadline. Later in the year, EAI intends to file an interim rate schedule with the APSC pursuant to Act 310 for recovery of costs incurred as of that time and intends to amend the interim rate schedule approximately every six months to capture ongoing costs.
Background: White Bluff Units 1 and 2 are required to meet more stringent NOx and SO2 limits by 2013 in order to comply with the Arkansas Department of Environmental Quality State Implementation Plan regulations implementing the United States Environmental Protection Agency's Regional Haze Rule. To continue operating, White Bluff must install pollution control technology. EAI has conducted economic analysis comparing the Environmental Controls project to other supply options for capacity and energy and concluded the project is the lowest reasonable cost alternative under a wide range of assumptions.

Entergy Texas

10.00%

Recent activity: On March 11, 2009, the PUCT approved the unanimous settlement which implemented interim rates effective January 28, 2009, for usage beginning December 19, 2008. The black box settlement called for a $46.7 million base rate increase, among other details, and stipulated 10% as a reasonable ROE.
Background: On September 26, 2007, ETI filed a rate case consisting of three major requests for relief: a $64.3 million base rate increase, a $43.2 million request for various riders, and a fuel reconciliation for the period January 2006 through March 2007 in the amount of $858 million. The rate case was based on a March 31, 2007 test year using an 11% ROE. Two competing non-unanimous settlement agreements were ultimately introduced and rejected. A unanimous settlement was reached by parties on December 16, 2008. Prior to the settlement, ETI operated under a base rate freeze since 1999. Legislation enacted in June 2005 extended the base rate freeze to mid 2008 but allowed ETI to file for rate relief through riders for incremental capacity costs (IPCR) and transition costs. In December 2005, the PUCT approved recovery of $18 million annual capacity costs, subject to reconciliation from September 2005. On January 23, 2008, an agreement was filed with the PUCT to increase the IPCR to $21 million and to add a surcharge for $10.3 million of unrecovered costs. In June 2006, the PUCT approved a settlement in the Transition to Competition (TTC) Cost recovery case, allowing ETI to recover $14.5 million per year in TTC costs over a 15-year period. The unanimous settlement eliminates the IPCR rider but does not affect the TTC rider.

Appendix C: Regulatory Summary Table (continued)

Company/ Proceeding

Authorized ROE

Pending Cases/Events
Retail Regulation
Entergy Texas

Qualified Power Region: On April 29, 2009, ETI filed its updated TTC plan indicating that it is agreeable to either stay in the Southeastern Reliability Council (SERC) or move to ERCOT, depending on the PUCT's policy direction. A prehearing conference is scheduled for May 11, 2009 to address the remainder of the procedural schedule. In addition, legislation has been introduced in Texas addressing TTC. In its current form, the legislation calls for ETI to cease all TTC activities, provides ETI the opportunity to recover certain transmission costs consistent with other companies outside of ERCOT to the extent not otherwise recovered and requires ETI to propose a competitive generation tariff. The legislation indicates the PUCT may initiate a proceeding to certify a power region when conditions supporting such a proceeding exist and that the PUCT may not approve a TTC plan until the expiration of four years from the time the region is certified. The Texas legislature adjourns June 1, 2009.
Background: In December 2006, ETI filed a TTC plan with the PUCT, proposing ETI join ERCOT as it represents the most viable path to full customer choice. To support a PUCT decision on the appropriate qualified power region, in October and November 2007, the PUCT issued orders in ETI's TTC case requiring further studies and approving Southwest Power Pool's (SPP) plan to develop information similar to that prepared by ERCOT and requiring an updated analysis of the benefits of ETI remaining in SERC. In May 2008, the PUCT issued an order directing ERCOT to update its study. In December 2008, ETI, ERCOT and SPP submitted updated studies. ERCOT filed a minor revision to its study on April 15, 2009 to incorporate additional contingencies.
 Storm Cost Recovery: On April 16, 2009, Governor Perry signed Senate Bill (SB) 769 enacting evergreen securitization legislation for recovery of system restoration costs, enabling ETI to initiate its storm recovery proceeding on April 21, 2009. ETI seeks recovery of $577.5 million of system restoration costs incurred through February 28, 2009, plus certain estimates, and authorization to recover in a financing proceeding to be subsequently filed, carrying costs on the approved system restoration costs at ETI's weighted average cost of capital (WACC).
Background: Pursuant to SB 769, the PUCT has 150 days after a company makes its filing to provide an order determining the amount eligible for recovery and securitization. A company may file for a financing order prior to the expiration of the 150-day period. The PUCT has 90 days after the company makes its filing to issue a financing order, but need not issue an order until it has determined costs eligible for recovery and securitization. The legislation also calls for system restoration costs to include carrying costs using the last approved WACC from the date on which system restoration costs were incurred until the date transition bonds are issued pursuant to a financing order or until costs are otherwise recovered pursuant to SB 769.

Entergy Gulf States Louisiana

9.90% - 11.40%

Recent activity: The LPSC Staff continues to review the 2007 test year Formula Rate Plan (FRP) filing. Rate changes to date for the filing, subject to refund, include the $5.6 million revenue deficiency plus $21.2 million for capacity cost recovery.
Background: In March 2005, the LPSC approved a Global Settlement which established an FRP with a 10.65% ROE midpoint and a +/- 75 basis point bandwidth and a recovery mechanism for Commission-approved capacity additions. Earnings outside the bandwidth are allocated 60% to customers and 40% to the company. On August 25, 2008, EGSL filed to implement rates for the 2007 test year filing subject to refund effective for the first billing cycle of September. The August 25, 2008 filing indicated a 9.23% ROE, which is below the allowed bandwidth. The $5.6 million revenue deficiency was partially offset by $4.1 million reduced capacity cost recovery, with subsequent capacity approvals increasing rates an additional $25.3 million. On September 29, 2008, EGSL filed to implement a further increase for the Ouachita Purchased Power Agreement (PPA) and filed on November 25, 2008 to implement an increase for the Calpine Carville PPA. The 2006 test year filing was the third of three approved filings by the LPSC. The FRP may be extended by mutual agreement of EGSL and the LPSC, and the parties agreed to extend the FRP one additional year. EGSL is interested in pursuing a further extension and continues to have discussions with the LPSC Staff concerning this matter.
Storm Cost Recovery: EGSL anticipates initiating its storm proceeding in the very near future.
Background: EGSL's restoration cost estimate for hurricanes Gustav and Ike is $240 to $255 million. In lieu of seeking interim recovery, on October 9, 2008, EGSL accessed $85 million of storm reserves funded by securitized debt proceeds. On October 15, 2008, the LPSC approved EGSL's request to defer and accrue carrying cost on unrecovered storm expenditures during the period the company seeks regulatory recovery. The approval was without prejudice to the ultimate resolution of the total amount of prudently incurred storm cost or final carrying cost rate. New securitization legislation is not needed, as existing legislation extends to Gustav and Ike.

Entergy Louisiana

9.45% - 11.05%

Recent activity: On March 23, 2009, the Administrative Law Judge (ALJ) ruled against ELL on 2006 test year issues subject to hearing in the fall of 2008. On April 6, 2009, ELL filed exceptions to the proposed ALJ recommendations on the three remaining issues, Cash Point, stock options and fixed cost contribution from lost customers. LPSC Staff and intervenors have since filed replies to ELL's exceptions. The ALJ will submit a final recommendation to the LPSC for a vote which could come this summer. The test year 2007 FRP outcome is also pending.
Background: In May 2005, the LPSC approved a settlement reestablishing the Company's FRP with a 10.25% ROE midpoint and a +/- 80 basis point bandwidth and a recovery mechanism for Commission-approved capacity additions. Earnings outside the bandwidth are allocated 60% to customers and 40% to the company. The 2007 test year filing is the third of three approved filings by the LPSC. The FRP may be extended by the mutual agreement of ELL and the LPSC. ELL is interested in pursuing an extension and continues to have discussions with the LPSC Staff concerning this matter. ELL's 2006 test year filing made in May 2007 indicated a 7.6% ROE. On September 27, 2007, ELL implemented an $18.4 million increase, subject to refund, $23.8 million representing a 60% adjustment to reach the bottom of the FRP band, net of $5.4 million for reduced capacity cost recovery. The LPSC allowed ELL to defer the difference between the $39.8 million requested for unrecovered fixed costs for extraordinary customer losses associated with Hurricane Katrina and the $23.8 million 60% adjustment as a regulatory asset, pending ultimate LPSC resolution of the 2006 FRP filing. On October 29, 2007, ELL implemented a $7.1 million FRP decrease which is primarily due to the reclassification of certain franchise fees from base rates to collection via a line item on customer's bills pursuant to an LPSC General Order. On August 25, 2008, ELL filed to implement rates for the 2007 test year filing subject to refund, effective for the first billing cycle of September. The August 25, 2008 filing indicated a 9.14% ROE, which is below the allowed bandwidth. The new rates reflect a $4.3 million revenue deficiency plus $12.6 million of additional capacity cost recovery. ELL also continues to seek resolutions of its 2006 test year FRP filing, including extraordinary customer loss recovery, and a hearing was conducted at the end of September 2008. ELL continued to pursue extraordinary customer losses in its 2007 test year filing by submitting a second scenario of the filing reflecting unrecovered fixed costs.

 Appendix C: Regulatory Summary Table (continued)

Company/ Proceeding

Authorized ROE

Pending Cases/Events
Retail Regulation

Storm Cost Recovery: ELL anticipates initiating its storm proceeding in the very near future.
Background: ELL's restoration cost estimate for hurricanes Gustav and Ike is $390 to $405 million. In lieu of seeking interim recovery, on October 9, 2008, ELL accessed $134 million of storm reserves funded by securitized debt proceeds. On October 15, 2008, the LPSC approved ELL's request to defer and accrue carrying cost on unrecovered storm expenditures during the period the company seeks regulatory recovery. The approval was without prejudice to the ultimate resolution of the total amount of prudently incurred storm cost or final carrying cost rate. New securitization legislation is not needed, as existing legislation extends to Gustav and Ike.
Little Gypsy Repowering: On March 11, 2009, the LPSC issued an order directing ELL to temporarily suspend the Little Gypsy Repowering Project and file a report with the LPSC on the economic viability of the project and develop a recommendation regarding whether to delay the project for an extended time. This action was based upon a number of factors including the recent decline in natural gas prices, as well as environmental concerns, the unknown costs of carbon legislation and changes in the capital/financial markets. On April 1, 2009, ELL recommended to the LPSC that it continue the temporary project suspension and make a filing with the LPSC seeking a longer-term suspension (three years or more) of the project. The LPSC order approving the project includes a recovery provision for prudently incurred costs in the event circumstances changed materially. The filing indicated approximately $160 million of spending through February 28, 2009 and estimated approximately $300 million of total costs if the project is cancelled. ELL had obtained all major environmental permits required to begin construction. A longer-term delay places these permits at risk and may adversely affect the project's economics and technological feasibility in the event the project is re-initiated. The LPSC discussed the filing at its business and executive session on April 8, 2009, and ELL plans to proceed as outlined in the recommendation. On April 21, 2009, the LPSC extended the temporary suspension of the Phase II procedural schedule and ordered that within 60 days, ELL/EGSL make a further filing seeking action with respect to the Phase II claims as appropriate under whatever ruling is forthcoming from the LPSC regarding the future of the Little Gypsy project.
Background: On November 8, 2007, the LPSC voted unanimously to approve ELL's request to repower the 538 MW Little Gypsy unit to utilize CFB technology relying on a dual-fuel approach (petroleum coke and coal), an action that could reduce Louisiana customers' dependence on natural gas. The approval was subject to a number of conditions, including the development and approval of a construction monitoring plan. On December 21, 2007, ELL initiated a Phase II proceeding seeking cash earnings on CWIP and approval for the procedure to synchronize permanent base rate recovery when the project is placed in service, via an FRP or base rate filing. This proceeding was suspended temporarily to allow ELL to develop an updated project cost estimate and schedule to account for a delay resulting from the need to conduct additional environmental analysis (Maximum Achievable Control Technology application) as a result of a federal court decision in February 2008 unrelated to the project. The additional analysis estimated construction could commence by mid-year 2009 leading to a targeted in service date by mid-year 2013 and resulting in a project cost estimate increase to $1.76 billion. ELL made its first quarterly monitoring plan filing at the end of July and on October 16, 2008 supplemented and resumed its Phase II proceeding, adding a recommendation to allocate one-third of the project to EGSL. On December 9, 2008, ELL filed a motion to consolidate the Waterford 3 Steam Generator Replacement Phase II filing request for cash earnings on CWIP with the Little Gypsy Phase II filing. In February 2009, the Louisiana Department of Environmental Quality issued the new air permit. ELL also continued to make its quarterly monitoring plan filings.
Waterford 3 Steam Generator Replacement: ELL is evaluating next steps for the Phase II request for cash earnings on CWIP for the steam generator replacement project while the consolidated Little Gypsy/Waterford 3 proceeding is temporarily suspended. On March 31, 2009, ELL filed its first quarterly monitoring report detailing progress on the project to date.
Background: On June 26, 2008, ELL petitioned the LPSC to replace two steam generators, the reactor vessel closure head and control drive mechanisms, at an expected cost of $511 million. The petition seeks relief in two phases. Phase I seeks certification within 120 days that the public convenience and necessity would be served by undertaking this project. Among other relief requested, ELL is also seeking approval for the procedure to synchronize permanent base rate recovery when the project is placed in service, via an FRP or base rate filing. In its Phase II filing, ELL is seeking cash earnings on CWIP. Due to careful maintenance, Waterford 3 is one of the last nuclear plants of its type to have to replace its steam generators. Of the 14 plants in the U.S. with similar pressurized water reactor designs, only one other plant has not replaced the equipment already. Replacing the reactor vessel closure head and control element drive mechanisms at the same time allows ELL to do the work more efficiently and economically. The long-lead time to design, manufacture and transport some of the required equipment to the site requires approval now in order to perform the project in 2011. On November 12, 2008, the LPSC approved the stipulated settlement, finding that the decision to undertake this project at an estimated cost of $511 million is prudent and the timing concurrent with the 2011 outage is reasonable. Prudent costs will be eligible for recovery through ELL's formula rate plan, if extended, or a base rate case filing. ELL shall undertake a future prudence review to consider at least project management, cost controls, success in achieving stated objectives, project replacement cost, and outage length / replacement power costs. ELL will also provide high level quarterly status reports on budget, schedule and business issues. On December 9, 2008, ELL initiated the filing to consolidate the Phase II request with the Little Gypsy Phase II proceeding, consistent with the LPSC's direction.

Appendix C: Regulatory Summary Table (continued)

Company/ Proceeding

Authorized ROE

Pending Cases/Events
Retail Regulation
Entergy Mississippi

9.46% - 12.24%

Recent activity: On March 13, 2009, EMI made its 2008 test year FRP filing indicating an earned ROE of 7.41% compared to a 13.16% midpoint ROE, including 69 basis points for performance incentives (band is 11.91% - 14.42%). The filing indicated a $27 million revenue deficiency, with a $14.5 million maximum increase allowed. The Mississippi Public Utilities Staff (MPUS) has since disputed the filing, extending the resolution deadline to June 30, 2009. Any approved changes in rates would be effective for bills rendered on and after May 1, 2009. In addition, on March 31, 2009, the Mississippi Supreme Court issued a briefing schedule in the 2007 test year FRP appeal case, with EMI's brief due May 11, 2009, followed 30 days later by the MPSC's reply brief.
Background: EMI has been operating under a FRP last approved in December 2002. The FRP allows the company's earned ROE to increase or decrease within a bandwidth with no change in rates. Earnings outside the bandwidth are allocated 50% to customers and 50% to the company, but on a prospective basis only. The plan also provides for performance incentives that can increase or decrease the benchmark ROE by as much as 100 basis points. On March 14, 2008, EMI made its 2007 test year FRP filing indicating an earned ROE of 9.42% compared to a 12.34% midpoint ROE, including 92 basis points for performance incentives (band is 11.08% - 13.6%). The filing called for an annual revenue increase of $10.1 million. On June 20, 2008, EMI reached a settlement with the MPUS, resulting in a $3.775 million rate increase. On January 8, 2009, the MPSC rejected the MPUS settlement, finding that rates currently in effect are just and reasonable and shall continue in effect pending the MPSC's review of the provisions of the rider FRP and possible amendments thereto. On January 22, 2009, EMI appealed the MPSC decision to the Mississippi Supreme Court, given the order denied the settlement increase with virtually no explanation.
Fuel Recovery/Attorney General Complaint: The MPSC continues to investigate issues associated with EMI fuel costs and claims raised by the Mississippi Attorney General (AG) going back some 30 years. On February 10, 2009, an independent audit report commissioned by the MPSC to review fuel recovery was issued. The report indicated that many of EMI's fuel procurement and adjustment practices are sound and in the customers' best interest.
Background: The relatively new Commission has been reviewing state utilities' practices and procedures, most notably related to fuel recovery. EMI understands the MPSC's need to obtain more information about past Commission actions, system tariffs, and issues including fuel purchases, fuel costs and power generation needs, and will continue to work with the Commission to inform, respond to questions and develop alternative policies on tariffs if they are found to be in the best interests of customers and fairly balanced with other stakeholder rights. In addition, the AG issued civil investigative demands directed at EMI and other Entergy companies related to EMI's fuel adjustment clause and other matters. The AG voluntarily dismissed this proceeding, and instead filed a complaint in state court in December 2008 against EMI and other Entergy companies alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution. The litigation is wide ranging and relates to tariffs and procedures under which EMI obtains power in the wholesale market to meet electricity demand. EMI believes the complaint is unfounded, should be resolved in the appropriate regulatory forum and should not be tried in the court of public opinion. On December 29, 2008, the affected Entergy companies filed to remove the AG's suit to U.S. District Court (the appropriate forum to resolve the types of federal issues raised in the suit) where it is currently pending, and additionally answered the complaint and filed a counter-claim for injunctive and other relief based upon the Mississippi Public Utilities Act and the Federal Power Act. The AG has filed a pleading seeking to remand the case to state court.
Storm Cost Recovery: EMI continues to evaluate whether the storm restoration costs will meet the threshold to draw upon the reserves.
Background: EMI's restoration cost estimate for Hurricane Gustav is $18 to $20 million. As of the end of March, EMI had $32 million of storm reserves funded by securitized debt proceeds.

Entergy New Orleans

11.1% Electric
10.75% Gas

Recent activity: On April 2, 2009, the City Council of New Orleans (CCNO) approved a comprehensive settlement for ENOI's rate case. Key provisions of the agreement include a total electric bill reduction of $35.3 million, including conversion of the $10.6 million voluntary recovery credit to a permanent reduction and complete realignment of Grand Gulf recovery from fuel to base rates, and a $4.95 million gas rate increase, both effective June 1, 2009. A new three year FRP was also adopted, with terms including an 11.1% electric ROE and a +/- 40 basis point bandwidth and a 10.75% gas ROE with a +/- 50 basis point bandwidth. Earnings outside the bandwidth reset prospectively to the midpoint ROE, with the difference flowing to customers or the company depending on whether ENOI is over or under-earning. The FRP also includes a recovery mechanism for Council-approved capacity additions, plus provisions for extraordinary cost changes and force majeure. Finally, the settlement implements energy conservation and demand programs, provides a right of first refusal for up to a 20 percent interest in a potential Amite South generation resource and includes the short-term opportunity to lock-in certain fuel costs for summer 2009 through a financial hedge.
Background: Prior to Hurricane Katrina, ENOI operated under a FRP with a ROE midpoint of 10.75%, a 45% hypothetical equity ratio, and electric and gas ROE bandwidths of 100 and 50 basis points, respectively. Pursuant to the 2006 post-Katrina rate agreement, ENOI filed its required rate case on July 31, 2008. The filing included a Period I (12/31/07) and Period II (Pro forma 12/31/08) test year case. ENOI proposed to reduce electric rates by approximately $23 million and increase gas base rates by $9.1 million. The electric reductions included $12.3 million through the fuel adjustment clause to realign Grand Gulf non-fuel operations and maintenance recovery to base rates and $10.6 million to convert the voluntary recovery credit to a permanent reduction. The rate case proposed an 11.75% ROE. On November 13, 2008, ENOI amended its rate filing to incorporate storm reserve treatment inadvertently omitted from the 2008 forecast Period II pro forma test year. The order also allowed ENOI to seek reinstatement of an appropriate FRP following the resetting of rates in 2009. Further, with New Orleans' recovery also taking place faster than expected, in December 2007, ENOI announced a voluntary plan to return an estimated $10.6 million to customers through a 6.15% base rate credit on electric bills.
Storm Cost Recovery: The ENOI comprehensive rate settlement also addressed storm recovery for hurricanes Gustav and Ike. ENOI will continue to access storm reserves until all deferred operation and maintenance costs have been recovered. Capital costs (including carrying charges) shall be included in rate base as of December 31, 2009 and reflected in ENOI's initial annual FRP filing. In the interim, when rates become effective June 1, 2009, ENOI shall include capital costs in a deferred asset account until ENOI begins recovering such costs through base rates, with said costs accruing carrying charges computed using ENOI's 2009 WACC or WACC as authorized in the rate settlement.
Background: ENOI's restoration cost estimate for hurricanes Gustav and Ike is $28 to $35 million. On October 9, 2008, ENOI accessed $10 million of storm reserves.

 

Appendix C: Regulatory Summary Table (continued)

Company/ Proceeding

Authorized ROE

Pending Cases/Events
Wholesale Regulation (FERC)
System Energy Resources, Inc.

10.94%

 Recent activity: None.
Background: ROE approved by July 2001 FERC order.
     
System Agreement

 

NA

Recent activity: Further progress on a proposed framework for a Successor Arrangement to the System Agreement could be stalled until FERC resolves EAI's and EMI's notices of cancellation filing made February 2, 2009.
Background: The System Agreement case addresses the allocation of production costs among the utility operating subsidiaries. In June 2005, the FERC issued its decision and established a bandwidth of +/- 11% to reallocate production costs and ordered that this approach be applied prospectively. In December 2005, FERC established, among other things, that 1) the bandwidth would be applied to calendar year 2006 actual production costs and 2) 2007 would be the first possible year of payments among Entergy's operating companies. The orders were appealed and the DC Circuit remanded to the FERC for reconsideration of the FERC's conclusion it did not have the authority to order refunds and the decision to delay the implementation of the bandwidth remedy. The remand is pending at FERC. The LPSC also appealed to the DC Circuit the FERC Orders approving the Operating Companies compliance filing implementing the bandwidth remedy. That appeal is currently pending before the Court, with oral argument scheduled for May 8, 2009. The Entergy Operating Companies submitted bandwidth filings for the calendar years 2006 and 2007 production costs. The Operating Companies will submit their next filing in May 2009. The calendar year 2008 preliminary estimate indicates a payment from EAI in the amount of $394 million collectively to EGSL, ETI, ELL and EMI. On September 23, 2008, the ALJ issued a decision regarding the initial bandwidth proceeding related to calendar year 2006 production costs, that concluded that, with one exception, the Operating Company calculation was appropriate and that the Operating Companies' production costs were prudently incurred. The one exception would require the Operating Companies to calculate nuclear depreciation/decommissioning for each facility based on the NRC license life. The hearing on the bandwidth proceeding related to calendar year 2007 production costs is currently scheduled to commence June 4, 2009. On September 19, 2008, FERC issued an order on rehearing in the proceeding involving the exclusion of interruptible loads from certain System Agreement calculations that concluded that FERC had authority to order refunds and that refunds were appropriate. The APSC and the Operating Companies appealed the FERC's orders to the DC Circuit. The System Agreement has been and continues to be the subject of ongoing litigation. As a result, EAI and EMI submitted their eight year notices to withdraw from the System Agreement in December 2005 and November 2007, respectively, and on February 2, 2009 filed with the FERC their notices of cancellation of their respective System Agreement rate schedules, effective December 2013 and November 2015, respectively. EAI and EMI have requested FERC issue a decision on the notices of cancellation by June 1, 2009 or, if further inquiry is necessary, that FERC institute a paper hearing to resolve the major policy and legal issues by the end of the year and then, if necessary, set any remaining factual questions for expedited hearing. The Operating Companies are considering a Successor Arrangement for the System Agreement.

 

Appendix D-1 provides comparative financial performance measures for the current quarter. Appendix D-2 provides historical financial performance measures and operating performance metrics for the trailing eight quarters. Financial performance measures in both tables include those calculated and presented in accordance with generally accepted accounting principles (GAAP), as well as those that are considered non-GAAP measures.

As-reported measures are computed in accordance with GAAP as they include all components of earnings, including special items. Operational measures are non-GAAP measures as they are calculated using operational earnings, which excludes the impact of special items. A reconciliation of operational measures to as-reported measures is provided in Appendix G.

Appendix D-1: GAAP and Non-GAAP Financial Performance Measures

First Quarter 2009 vs. 2008
(see appendix F for definitions of certain measures)

For 12 months ending March 31

2009

2008

Change

GAAP Measures

Return on average invested capital - as-reported

7.6%

8.8%

(1.2)%

Return on average common equity - as-reported

14.1%

15.9%

(1.8)%

Net margin - as-reported

8.8%

10.6%

(1.8)%

Cash flow interest coverage

6.5

4.9

1.6

Book value per share

$44.02

$39.99

$4.03

End of period shares outstanding (millions)

196.1

191.9

4.2

Non-GAAP Measures

Return on average invested capital - operational

8.0%

9.0%

(1.0)%

Return on average common equity - operational

15.0%

16.3%

(1.3)%

Net margin - operational

9.4%

10.8%

(1.4)%

As of March 31 ($ in millions)

2009

2008

Change

GAAP Measures

Cash and cash equivalents

1,803

916

887

Revolver capacity

725

1,503

(778)

Total debt

12,034

11,292

742

Debt to capital ratio

57.4%

58.6%

(1.2)%

Off-balance sheet liabilities:

Debt of joint ventures - Entergy's share

124

134

(10)

Leases - Entergy's share

449

508

(59)

Total off-balance sheet liabilities

573

642

(69)

Non-GAAP Measures

Total gross liquidity

2,528

2,419

109

Net debt to net capital ratio

53.4%

56.5%

(3.1)%

Net debt ratio including off-balance sheet liabilities

54.7%

58.0%

(3.3)%

Appendix D-2: Historical Performance Measures
(see appendix F for definitions of measures)

2Q07

3Q07

4Q07

1Q08

2Q08

3Q08

4Q08

1Q09

08YTD

09YTD

Financial

EPS - as-reported ($)

1.32

2.30

0.96

1.56

1.37

2.41

0.89

1.20

1.56

1.20

Less - special items ($)

0.00

0.00

(0.16)

0.00

(0.09)

(0.09)

(0.10)

(0.09)

0.00

(0.09)

EPS - operational ($)

1.32

2.30

1.12

1.56

1.46

2.50

0.99

1.29

1.56

1.29

Trailing Twelve Months

ROIC - as-reported (%)

8.2

8.6

8.3

8.8

8.6

8.1

8.1

7.6

ROIC - operational (%)

7.6

8.1

8.5

9.0

8.8

8.4

8.4

8.0

ROE - as-reported (%)

14.2

14.6

14.1

15.9

16.3

15.6

15.4

14.1

ROE - operational (%)

12.9

13.4

14.5

16.3

17.0

16.4

16.1

15.0

Cash flow interest coverage

5.8

5.3

5.0

4.9

5.0

7.0

6.5

6.5

Debt to capital ratio (%)

57.3

57.3

57.6

58.6

60.7

60.4

59.7

57.4

Net debt/net capital ratio (%)

54.1

53.9

54.7

56.5

58.3

54.9

55.6

53.4

Utility

GWh billed

Residential

6,986

11,128

7,376

8,011

7,372

10,671

6,992

7,893

8,011

7,893

Commercial & Gov't

7,043

8,748

7,290

6,807

7,275

8,646

6,992

6,756

6,807

6,756

Industrial

9,813

10,120

9,729

9,377

9,730

10,110

8,626

8,139

9,377

8,139

Wholesale

1,428

1,413

1,666

1,290

1,440

1,431

1,240

1,387

1,290

1,387

O&M expense/MWh (o)

$19.01

$15.16

$20.16

$17.26

$19.48

$14.43

$23.95

$18.51

$17.26

$18.51

Reliability

    SAIFI (p)

1.9

1.8

1.8

1.9

1.9

1.9

1.9

1.8

1.9

1.8

    SAIDI (p)

198

188

184

191

215

227

216

209

191

209

Nuclear

Net MW in operation

4,998

4,998

4,998

4,998

4,998

4,998

4,998

4,998

4,998

4,998

Avg. realized price per MWh

$51.28

$53.11

$51.52

$61.47

$58.22

$61.59

$56.69

$63.84

$61.47

$63.84

Production cost/MWh (o)

$21.27

$20.90

$22.64

$19.98

$23.11

$21.77

$22.77

$23.14

$19.98

$23.14

Non-fuel O&M expense/
purchased power per MWh (o)

$24.09

$22.40

$23.94

$20.20

$23.42

$21.19

$23.06

$22.44

$20.20

$22.44

GWh billed

8,896

10,105

10,254

10,760

10,145

10,316

10,489

10,074

10,760

10,074

Capacity factor

82%

93%

92%

97%

92%

95%

94%

92%

97%

92%

    (o) 4Q07 excludes the effect of the nuclear alignment special.
    (p) Excludes impact of major storm activity.

 

Appendix E: Planned Capital Expenditures

Entergy's capital plan from 2009 through 2011 anticipates $6.5 billion for investment, including $2.5 billion of maintenance capital. The remaining $4.0 billion is for specific investments such as the balance of Utility storm capital spending and the Utility's portfolio transformation strategy, the steam generator replacement at Entergy Louisiana's Waterford 3 nuclear unit, environmental compliance spending (i.e., spending for the installation of scrubbers and low NOx burners at Entergy Arkansas' White Bluff coal plant), transmission upgrades, dry cask storage, nuclear license renewal efforts, NYPA value sharing, the Indian Point Independent Safety Evaluation, and other initiatives.

The three year capital plan includes $1.1 billion for the Little Gypsy repowering project for which Entergy Louisiana plans to make a filing seeking a long-term suspension (three years or more). Spending through December 31, 2008 was reported at $135 million. $300 million is the total projected spending in the event Little Gypsy is canceled. In addition, the Utility incurred additional storm spending for the January 2009 Arkansas ice storm ranging from $55 to $60 million.

Appendix E: 2009-2011 Planned Capital Expenditures

($ in millions) - Prepared January 2009

2009

2010

2011

Total

Maintenance capital

        

  Utility, Parent & Other

746

723

721

2,190

  Entergy Nuclear

90

84

94

268

  Non-Nuclear Wholesale Assets

-

-

-

-

     Subtotal

836

807

815

2,458

Other capital commitments

        

  Utility, Parent & Other

806

993

1,074

2,873

  Entergy Nuclear

357

277

262

896

  Non-Nuclear Wholesale Assets

-

-

-

-

     Subtotal

1,163

1,270

1,336

3,769

Total Planned Capital Expenditures

1,999

2,077

2,151

6,227

Storm Capital

164

44

35

243

Total Planned Capital Expenditures Including Storm Capital

2,163

2,121

2,186

6,470

Appendix F provides definitions of certain operational performance measures, as well as GAAP and non-GAAP financial measures, all of which are referenced in this release.

Appendix F: Definitions of Operational Performance Measures and GAAP and Non-GAAP Financial Measures

Utility

GWh billed

Total number of GWh billed to all retail and wholesale customers

Operation & maintenance expense

Operation, maintenance and refueling expenses per MWh of billed sales, excluding fuel

SAIFI

System average interruption frequency index; average number per customer per year

SAIDI

System average interruption duration index; average minutes per customer per year

Number of customers

Number of customers at end of period

Competitive Businesses

Planned TWh of generation

Amount of output expected to be generated by Entergy Nuclear for nuclear units considering plant operating characteristics, outage schedules, and expected market conditions which impact dispatch

Percent of planned generation sold
forward

Percent of planned generation output sold forward under contracts, forward physical contracts, forward financial contracts or options (consistent with assumptions used in earnings guidance) that may or may not require regulatory approval

Unit-contingent

Transaction under which power is supplied from a specific generation asset; if the asset is unavailable, seller is not liable to buyer for any damages

Unit-contingent with availability
guarantees

Transaction under which power is supplied from a specific generation asset; if the asset is unavailable, seller is not liable to buyer for any damages, unless the actual availability over a specified period of time is below an availability threshold specified in the contract

Firm LD

Transaction that requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset) or settles financially on notional quantities; if a party fails to deliver or receive energy, defaulting party must compensate the other party as specified in the contract

Planned net MW in operation

Amount of capacity to be available to generate power considering uprates planned to be completed within the calendar year

Bundled energy & capacity contract

A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold

Capacity contract

A contract for the sale of the installed capacity product in regional markets managed by ISO New England and the New York Independent System Operator

Average contract price per MWh or
per kW per month

Price at which generation output and/or capacity is expected to be sold to third parties, given existing contract or option exercise prices based on expected dispatch or capacity, excluding the revenue associated with the amortization of the below-market PPA for Palisades

Average contract revenue per MWh

Price at which the combination of generation output and capacity are expected to be sold to third parties, given existing contract or option exercise prices based on expected dispatch

Entergy Nuclear

Net MW in operation

Installed capacity owned and operated by Entergy Nuclear

Average realized price per MWh

As-reported revenue per MWh billed for all non-utility nuclear operations

Production cost per MWh

Fuel and non-fuel operation and maintenance expenses according to accounting standards that directly relate to the production of electricity per MWh

Non-fuel O&M expense/purchased
power per MWh

Operation, maintenance and refueling expenses and purchased power per MWh billed, excluding fuel

GWh billed

Total number of GWh billed to all customers

Capacity factor

Normalized percentage of the period that the plant generates power

Refueling outage duration

Number of days lost for scheduled refueling outage during the period

Financial measures defined in the below table include measures prepared in accordance with generally accepted accounting principles, (GAAP), as well as non-GAAP measures. Non-GAAP measures are included in this release in order to provide metrics that remove the effect of less routine financial impacts from commonly used financial metrics.

Appendix F: Definitions of Operational Performance Measures and GAAP and Non-GAAP Financial Measures (continued)

Financial Measures - GAAP

Return on average invested capital - as-reported

12-months rolling earnings adjusted to include preferred dividends and tax-effected interest expense divided by average invested capital

Return on average common equity - as-reported

12-months rolling earnings divided by average common equity

Net margin - as-reported

12-months rolling earnings divided by 12 months rolling revenue

Cash flow interest coverage

12-months cash flow from operating activities plus 12-months rolling interest paid, divided by interest expense

Book value per share

Common equity divided by end of period shares outstanding

Revolver capacity

Amount of undrawn capacity remaining on corporate and subsidiary revolvers

Total debt

Sum of short-term and long-term debt, notes payable, capital leases, and preferred stock with sinking fund on the balance sheet less non-recourse debt, if any

Debt of joint ventures (Entergy's share)

Debt issued by Non-Nuclear Wholesale Assets business joint ventures

Leases (Entergy's share)

Operating leases held by subsidiaries capitalized at implicit interest rate

Debt to capital

Gross debt divided by total capitalization

Financial Measures - Non-GAAP

Operational earnings

As-reported earnings applicable to common stock adjusted to exclude the impact of special items

Return on average invested capital - operational

12-months rolling operational earnings adjusted to include preferred dividends and tax-effected interest expense divided by average invested capital

Return on average common equity - operational

12-months rolling operational earnings divided by average common equity

Net margin - operational

12-months rolling operational earnings divided by 12 months rolling revenue

Earnings before interest, income taxes, depreciation and amortization and interest and dividend income (EBITDA)

Net Income plus interest expense, income taxes, depreciation and amortization and miscellaneous other income less other income

Total gross liquidity

Sum of cash and revolver capacity

Net debt to net capital

Gross debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents

Net debt including off-balance sheet liabilities

Sum of gross debt and off-balance sheet debt less cash and cash equivalents divided by sum of total capitalization and off-balance sheet debt less cash and cash equivalents

 

Appendices G-1 and G-2 provide reconciliations of various non-GAAP financial measures disclosed in this release to their most comparable GAAP measure.

Appendix G-1: Reconciliation of GAAP to Non-GAAP Financial Measures - Return on Equity, Return on Invested
Capital and Net Margin Metrics

($ in millions)

2Q07

3Q07

4Q07

1Q08

2Q08

3Q08

4Q08

1Q09

As-reported earnings-rolling 12 months (A)

1,137

1,209

1,135

1,231

1,235

1,244

1,221

1,147

Preferred dividends

26

25

25

24

23

21

20

20

Tax effected interest expense

365

392

392

396

390

375

374

366

As-reported earnings, rolling 12 months including preferred dividends and tax effected interest expense (B)

1,528

1,626

1,552

1,651

1,648

1,640

1,615

1,533

Special items in prior quarters

108

101

0

(32)

(32)

(50)

(35)

(55)

Special items 2Q07 thru 1Q09

Nuclear fleet alignment

(32)

Nuclear spin-off costs

(18)

(17)

(20)

(17)

Total special items (C)

108

101

(32)

(32)

(50)

(67)

(55)

(72)

Operational earnings, rolling 12 months including preferred dividends and tax effected interest expense (B-C)

1,420

1,525

1,584

1,683

1,698

1,707

1,670

1,605

Operational earnings, rolling 12 months (A-C)

1,029

1,108

1,167

1,263

1,285

1,311

1,276

1,219

Average invested capital (D)

18,652

18,866

18,721

18,790

19,244

20,236

19,927

20,126

Average common equity (E)

7,998

8,264

8,030

7,756

7,555

7,973

7,915

8,152

Operating revenues (F)

11,371

11,311

11,484

11,655

12,150

12,825

13,094

13,018

ROIC - as-reported (B/D)

8.2

8.6

8.3

8.8

8.6

8.1

8.1

7.6

ROIC - operational ((B-C)/D)

7.6

8.1

8.5

9.0

8.8

8.4

8.4

8.0

ROE - as-reported (A/E)

14.2

14.6

14.1

15.9

16.3

15.6

15.4

14.1

ROE - operational ((A-C)/E)

12.9

13.4

14.5

16.3

17.0

16.4

16.1

15.0

Net margin - as-reported (A/F)

10.0

10.7

9.9

10.6

10.2

9.7

9.3

8.8

Net margin - operational ((A-C)/F)

9.1

9.8

10.2

10.8

10.6

10.2

9.7

9.4

Appendix G-2: Reconciliation of GAAP to Non-GAAP Financial Measures - Credit and Liquidity Metrics

($ in millions)

2Q07

3Q07

4Q07

1Q08

2Q08

3Q08

4Q08

1Q09

Gross debt (A)

10,936

11,194

11,123

11,292

11,768

12,656

12,279

12,034

Less cash and cash equivalents (B)

1,320

1,467

1,254

916

1,086

2,556

1,920

1,803

Net debt (C)

9,616

9,728

9,869

10,376

10,682

10,100

10,359

10,231

Total capitalization (D)

19,088

19,529

19,297

19,276

19,401

20,944

20,557

20,975

Less cash and cash equivalents (B)

1,320

1,467

1,254

916

1,086

2,556

1,920

1,803

Net capital (E)

17,767

18,062

18,043

18,360

18,315

18,388

18,637

19,172

Debt to capital ratio % (A/D)

57.3

57.3

57.6

58.6

60.7

60.4

59.7

57.4

Net debt to net capital ratio % (C/E)

54.1

53.9

54.7

56.5

58.3

54.9

55.6

53.4

Off-balance sheet liabilities (F)

664

662

658

642

638

637

574

573

Net debt to net capital ratio including off-balance sheet liabilities % ((C+F)/(E+F))

55.8

55.5

56.3

58.0

59.7

56.4

56.9

54.7

Revolver capacity (G)

1,650

1,804

1,730

1,503

826

374

645

725

Gross liquidity (B+G)

2,970

3,271

2,984

2,419

1,912

2,930

2,565

2,528

 

Entergy Corporation's common stock is listed on the New York and Chicago exchanges under the symbol "ETR".

Additional investor information can be accessed on-line at
www.entergy.com/investor_relations

 

**********************************************************************************************************************

In this news release, and from time to time, Entergy Corporation makes certain "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Except to the extent required by the federal securities laws, Entergy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

Forward-looking statements involve a number of risks and uncertainties. There are factors that could cause actual results to differ materially from those expressed or implied in the forward-looking statements, including (a) those factors discussed in (i) Entergy's Form 10-K for the year ended December 31, 2008 and (ii) Entergy's other reports and filings made under the Securities Exchange Act of 1934, (b) the uncertainties associated with efforts to remediate the effects of Hurricanes Gustav and Ike and the January 2009 Arkansas ice storm and recovery of costs associated with restoration, and (c) the following transactional factors (in addition to others described elsewhere in this news release and in subsequent securities filings): (i) risks inherent in the contemplated spin-off, joint venture and related transactions (including the level of debt to be incurred by Enexus Energy Corporation and the terms and costs related thereto), (ii) legislative and regulatory actions, and (iii) conditions of the capital markets during the periods covered by the forward-looking statements. Entergy cannot provide any assurances that the spin-off or any of the proposed transactions related thereto will be completed, nor can it give assurances as to the terms on which such transactions will be consummated. The transaction is subject to certain conditions precedent, including regulatory approvals and the final approval by the Board of Directors of Entergy.

 

Entergy Corporation 
 
Consolidating Balance Sheet 
March 31, 2009 
(Dollars in thousands) 
(Unaudited) 
   
  U.S. Utilities/ Parent & Other   Competitive Businesses   Eliminations   Consolidated
ASSETS              
               
CURRENT ASSETS              
               
Cash and cash equivalents:               
  Cash $ 89,906    $ 4,466    $ -    $ 94,372 
  Temporary cash investments 1,216,019    492,567    -    1,708,586 
     Total cash and cash equivalents 1,305,925    497,033    -    1,802,958 
Securitization recovery trust account 19,893    -    -    19,893 
Notes receivable 5,452    1,336,373    (1,341,825)   - 
Accounts receivable:              
  Customer 441,621    175,511    -    617,132 
  Allowance for doubtful accounts (25,859)   -    -    (25,859)
  Associated companies 338,629    91,943    (430,572)   - 
  Other 139,561    15,468    -    155,029 
  Accrued unbilled revenues 248,683    -    -    248,683 
     Total accounts receivable 1,142,635    282,922    (430,572)   994,985 
Deferred fuel costs 19,527    -    -    19,527 
Accumulated deferred income taxes 36,232    -    -    36,232 
Fuel inventory - at average cost 230,440    3,336    -    233,776 
Materials and supplies - at average cost 505,347    276,932    -    782,279 
Deferred nuclear refueling outage costs 82,500    136,736    -    219,236 
System agreement cost equalization 394,000    -    -    394,000 
Prepayments and other 163,064    256,343    (56,927)   362,480 
TOTAL 3,905,015    2,789,675    (1,829,324)   4,865,366 
                
OTHER PROPERTY AND INVESTMENTS              
               
Investment in affiliates - at equity 7,321,710    (299,023)   (6,959,063)   63,624 
Decommissioning trust funds 1,094,526    1,624,163    -    2,718,689 
Non-utility property - at cost (less accumulated depreciation) 226,429    4,137    -    230,566 
Other 105,445    10,833    (5,388)   110,890 
TOTAL 8,748,110    1,340,110    (6,964,451)   3,123,769 
               
PROPERTY, PLANT, AND EQUIPMENT              
               
Electric 31,546,855    3,635,538    -    35,182,393 
Property under capital lease 745,152    -    -    745,152 
Natural gas 306,854    -    -    306,854 
Construction work in progress 1,233,712    327,518    -    1,561,230 
Nuclear fuel under capital lease 416,913    -    -    416,913 
Nuclear fuel 161,029    511,271    -    672,300 
TOTAL PROPERTY, PLANT AND EQUIPMENT 34,410,515    4,474,327    -    38,884,842 
Less - accumulated depreciation and amortization 15,666,402    598,763    -    16,265,165 
PROPERTY, PLANT AND EQUIPMENT - NET 18,744,113    3,875,564    -    22,619,677 
               
DEFERRED DEBITS AND OTHER ASSETS              
               
Regulatory assets:              
  SFAS 109 regulatory asset - net 607,706    -    -    607,706 
  Other regulatory assets 3,703,332    -    -    3,703,332 
  Deferred fuel costs 168,122    -    -    168,122 
Goodwill 374,099    3,073    -    377,172 
Other 755,382    914,596    (522,535)   1,147,443 
TOTAL 5,608,641    917,669    (522,535)   6,003,775 
               
TOTAL ASSETS $ 37,005,879    $ 8,923,018    $ (9,316,310)   $ 36,612,587 
               
*Totals may not foot due to rounding.              
 
 
 
Entergy Corporation 
 
Consolidating Balance Sheet 
March 31, 2009 
(Dollars in thousands) 
(Unaudited) 
   
  U.S. Utilities/ Parent & Other   Competitive Businesses   Eliminations   Consolidated
LIABILITIES AND SHAREHOLDERS' EQUITY              
               
CURRENT LIABILITIES              
               
Currently maturing long-term debt $ 545,511    $ 30,136    $ -    $ 575,647 
Notes payable:              
  Associated companies 1,324,210    17,615    (1,341,825)   - 
  Other 80,034    -    -    80,034 
Account payable:              
  Associated companies 398,925    7,774    (406,699)   - 
  Other 662,590    211,478    -    874,068 
Customer deposits 310,033    -    -    310,033 
Taxes accrued 128,824    (66,398)   -    62,426 
Interest accrued 147,799    2,097    -    149,896 
Deferred fuel costs 311,482    -    -    311,482 
Obligations under capital leases 162,415    -    -    162,415 
Pension and other postretirement liabilities 33,595    4,743    -    38,338 
System agreement cost equalization 460,315    -    -    460,315 
Other 163,090    125,000    (58,627)   229,463 
TOTAL 4,728,823    332,445    (1,807,151)   3,254,117 
               
NON-CURRENT LIABILITIES              
               
Accumulated deferred income taxes and taxes accrued 5,857,645    939,304    -    6,796,949 
Accumulated deferred investment tax credits 321,276    -    -    321,276 
Obligations under capital leases 294,257    -    -    294,257 
Other regulatory liabilities 284,239    -    -    284,239 
Decommissioning and retirement cost liabilities 1,465,242    1,251,844    -    2,717,086 
Accumulated provisions 131,395    8,317    -    139,712 
Pension and other postretirement liabilities 1,730,536    426,249    -    2,156,785 
Long-term debt 10,746,346    180,477    (5,388)   10,921,435 
Other 566,500    774,071    (555,277)   785,294 
TOTAL 21,397,436    3,580,262    (560,665)   24,417,033 
               
               
EQUITY              
               
Shareholders' Equity:              
  Common stock, $.01 par value, authorized 500,000,000 shares;              
   issued 254,772,087 shares in 2009 2,163,814    911,495    (3,072,761)   2,548 
  Paid-in capital 7,460,265    2,156,932    (4,246,751)   5,370,446 
  Retained earnings 5,380,457    1,814,044    289,454    7,483,955 
  Accumulated other comprehensive income (loss) (118,975)   58,257    626    (60,092)
  Less - treasury stock, at cost (58,693,564 shares in 2009) 4,286,451    12,700    (132,700)   4,166,451 
Total shareholders' equity 10,599,110    4,928,028    (6,896,732)   8,630,406 
Subsidiaries' preferred stock without sinking fund 280,510    82,283    (51,762)   311,031 
TOTAL 10,879,620    5,010,311    (6,948,494)   8,941,437 
               
TOTAL LIABILITIES AND EQUITY $ 37,005,879    $ 8,923,018    $ (9,316,310)   $ 36,612,587 
               
*Totals may not foot due to rounding.              
               

 

Entergy Corporation 
 
Consolidating Balance Sheet 
December 31, 2008
(Dollars in thousands)
(Unaudited)
   
  U.S. Utilities/ Parent & Other   Competitive Businesses   Eliminations   Consolidated
ASSETS              
               
CURRENT ASSETS              
               
Cash and cash equivalents:              
  Cash $ 110,203    $ 5,673    $ -    $ 115,876 
  Temporary cash investments 1,355,498    449,117    -    1,804,615 
     Total cash and cash equivalents 1,465,701    454,790    -    1,920,491 
Securitization recovery trust account 12,062    -    -    12,062 
Notes receivable 99,330    1,333,123    (1,432,453)   - 
Accounts receivable:              
  Customer 523,348    210,856    -    734,204 
  Allowance for doubtful accounts (25,610)   -    -    (25,610)
  Associated companies 139,912    84,341    (224,253)   - 
  Other 179,207    27,420    -    206,627 
  Accrued unbilled revenues 282,914    -    -    282,914 
     Total accounts receivable 1,099,771    322,617    (224,253)   1,198,135 
Deferred fuel costs 167,092    -    -    167,092 
Accumulated deferred income taxes 7,307    -    -    7,307 
Fuel inventory - at average cost 213,313    2,832    -    216,145 
Materials and supplies - at average cost 505,720    270,450    -    776,170 
Deferred nuclear refueling outage costs 106,514    115,289    -    221,803 
System agreement cost equalization 394,000    -    -    394,000 
Prepayments and other 106,044    144,200    (3,060)   247,184 
TOTAL 4,176,854    2,643,301    (1,659,766)   5,160,389 
               
OTHER PROPERTY AND INVESTMENTS              
               
Investment in affiliates - at equity 7,354,792    (296,465)   (6,992,080)   66,247 
Decommissioning trust funds 1,143,391    1,688,852    -    2,832,243 
Non-utility property - at cost (less accumulated depreciation) 226,333    4,782    -    231,115 
Other 103,308    10,019    (5,388)   107,939 
TOTAL 8,827,824    1,407,188    (6,997,468)   3,237,544 
               
PROPERTY, PLANT, AND EQUIPMENT              
               
Electric 30,878,491    3,616,915    -    34,495,406 
Property under capital lease 745,504    -    -    745,504 
Natural gas 303,769    -    -    303,769 
Construction work in progress 1,458,181    254,580    -    1,712,761 
Nuclear fuel under capital lease 465,374    -    -    465,374 
Nuclear fuel 130,675    506,138    -    636,813 
TOTAL PROPERTY, PLANT AND EQUIPMENT 33,981,994    4,377,633    -    38,359,627 
Less - accumulated depreciation and amortization 15,365,659    564,854    -    15,930,513 
PROPERTY, PLANT AND EQUIPMENT - NET 18,616,335    3,812,779    -    22,429,114 
                
DEFERRED DEBITS AND OTHER ASSETS              
               
Regulatory assets:              
  SFAS 109 regulatory asset - net 581,719    -    -    581,719 
  Other regulatory assets 3,615,104    -    -    3,615,104 
  Deferred fuel costs 168,122    -    -    168,122 
Goodwill 374,099    3,073    -    377,172 
Other 744,499    868,454    (565,299)   1,047,654 
TOTAL 5,483,543    871,527    (565,299)   5,789,771 
               
TOTAL ASSETS $ 37,104,556    $ 8,734,795    $ (9,222,533)   $ 36,616,818 
               
*Totals may not foot due to rounding.              
 
 
 
Entergy Corporation 
 
Consolidating Balance Sheet 
December 31, 2008
(Dollars in thousands)
(Unaudited)
   
  U.S. Utilities/ Parent & Other   Competitive Businesses   Eliminations   Consolidated
LIABILITIES AND SHAREHOLDERS' EQUITY              
               
CURRENT LIABILITIES              
               
Currently maturing long-term debt $ 514,911    $ 29,549    $ -    $ 544,460 
Notes payable:              
  Associated companies 1,341,198    91,255    (1,432,453)   - 
  Other 55,034    -    -    55,034 
Account payable:              
  Associated companies 97,530    126,413    (223,943)   - 
  Other 1,222,415    253,330    -    1,475,745 
Customer deposits 302,303    -    -    302,303 
Taxes accrued 175,920    (100,710)   -    75,210 
Interest accrued 185,778    1,532    -    187,310 
Deferred fuel costs 183,539    -    -    183,539 
Obligations under capital leases 162,393    -    -    162,393 
Pension and other postretirement liabilities 41,653    4,635    -    46,288 
System agreement cost equalization 460,315    -    -    460,315 
Other 146,808    129,549    (3,060)   273,297 
TOTAL 4,889,797    535,553    (1,659,456)   3,765,894 
               
NON-CURRENT LIABILITIES              
               
Accumulated deferred income taxes and taxes accrued 5,718,488    847,282    -    6,565,770 
Accumulated deferred investment tax credits 325,570    -    -    325,570 
Obligations under capital leases 343,093    -    -    343,093 
Other regulatory liabilities 280,643    -    -    280,643 
Decommissioning and retirement cost liabilities 1,447,659    1,229,836    -    2,677,495 
Accumulated provisions 136,449    11,003    -    147,452 
Pension and other postretirement liabilities 1,731,824    446,169    -    2,177,993 
Long-term debt 10,991,204    188,473    (5,388)   11,174,289 
Other 735,252    720,223    (574,477)   880,998 
TOTAL 21,710,182    3,442,986    (579,865)   24,573,303 
               
               
EQUITY              
               
Shareholders' Equity:              
Common stock, $.01 par value, authorized 500,000,000 shares;              
 issued 248,174,087 shares in 2008 2,163,749    911,494    (3,072,761)   2,482 
Paid-in capital 6,979,623    2,138,165    (4,248,485)   4,869,303 
Retained earnings 5,494,812    1,631,437    256,470    7,382,719 
Accumulated other comprehensive income (loss) (118,904)   5,580    626    (112,698)
Less - treasury stock, at cost (58,815,518 shares in 2008) 4,295,214    12,700    (132,700)   4,175,214 
Total shareholders' equity 10,224,066    4,673,976    (6,931,450)   7,966,592 
Subsidiaries' preferred stock without sinking fund 280,511    82,280    (51,762)   311,029 
TOTAL 10,504,577    4,756,256    (6,983,212)   8,277,621 
               
TOTAL LIABILITIES AND EQUITY $ 37,104,556    $ 8,734,795    $ (9,222,533)   $ 36,616,818 
               
*Totals may not foot due to rounding.              
               
               

 

Entergy Corporation 
 
Consolidating Balance Sheet 
March 31, 2009 vs December 31, 2008 
(Dollars in thousands) 
(Unaudited) 
   
  U.S. Utilities/ Parent & Other   Competitive Businesses   Eliminations   Consolidated
ASSETS              
               
CURRENT ASSETS              
               
Cash and cash equivalents:              
  Cash $ (20,297)   $ (1,207)   $ -    $ (21,504)
  Temporary cash investments (139,479)   43,450    -    (96,029)
     Total cash and cash equivalents (159,776)   42,243    -    (117,533)
Securitization recovery trust account 7,831    -    -    7,831 
Notes receivable (93,878)   3,250    90,628    - 
Accounts receivable:              
  Customer (81,727)   (35,345)   -    (117,072)
  Allowance for doubtful accounts (249)   -    -    (249)
  Associated companies 198,717    7,602    (206,319)   - 
  Other (39,646)   (11,952)   -    (51,598)
  Accrued unbilled revenues (34,231)   -    -    (34,231)
     Total accounts receivable 42,864    (39,695)   (206,319)   (203,150)
Deferred fuel costs (147,565)   -    -    (147,565)
Accumulated deferred income taxes 28,925    -    -    28,925 
Fuel inventory - at average cost 17,127    504    -    17,631 
Materials and supplies - at average cost (373)   6,482    -    6,109 
Deferred nuclear refueling outage costs (24,014)   21,447    -    (2,567)
System agreement cost equalization -    -    -    - 
Prepayments and other 57,020    112,143    (53,867)   115,296 
TOTAL (271,839)   146,374    (169,558)   (295,023)
               
OTHER PROPERTY AND INVESTMENTS              
               
Investment in affiliates - at equity (33,082)   (2,558)   33,017    (2,623)
Decommissioning trust funds (48,865)   (64,689)   -    (113,554)
Non-utility property - at cost (less accumulated depreciation) 96    (645)   -    (549)
Other 2,137    814    -    2,951 
TOTAL (79,714)    (67,078)   33,017    (113,775)
               
PROPERTY, PLANT, AND EQUIPMENT              
               
Electric 668,364    18,623    -    686,987 
Property under capital lease (352)   -    -    (352)
Natural gas 3,085    -    -    3,085 
Construction work in progress (224,469)   72,938    -    (151,531)
Nuclear fuel under capital lease (48,461)   -    -    (48,461)
Nuclear fuel 30,354    5,133    -    35,487 
TOTAL PROPERTY, PLANT AND EQUIPMENT 428,521    96,694    -    525,215 
Less - accumulated depreciation and amortization 300,743    33,909    -    334,652 
PROPERTY, PLANT AND EQUIPMENT - NET 127,778    62,785    -    190,563 
               
DEFERRED DEBITS AND OTHER ASSETS              
               
Regulatory assets:              
  SFAS 109 regulatory asset - net 25,987    -    -    25,987 
  Other regulatory assets 88,228    -    -    88,228 
  Deferred fuel costs -    -    -    - 
Goodwill -    -    -    - 
Other 10,883    46,142    42,764    99,789 
TOTAL 125,098    46,142    42,764    214,004 
               
TOTAL ASSETS $ (98,677)   $ 188,223    $ (93,777)   $ (4,231)
               
*Totals may not foot due to rounding.              
 
 
 
Entergy Corporation 
 
Consolidating Balance Sheet 
March 31, 2009 vs December 31, 2008 
(Dollars in thousands) 
(Unaudited) 
   
  U.S. Utilities/ Parent & Other   Competitive Businesses   Eliminations   Consolidated
LIABILITIES AND SHAREHOLDERS' EQUITY              
               
CURRENT LIABILITIES              
               
Currently maturing long-term debt $ 30,600    $ 587    $ -    $ 31,187 
Notes payable:              
  Associated companies (16,988)   (73,640)   90,628    - 
  Other 25,000    -    -    25,000 
Account payable:               
  Associated companies 301,395    (118,639)   (182,756)   - 
  Other (559,825)   (41,852)   -    (601,677)
Customer deposits 7,730    -    -    7,730 
Taxes accrued (47,096)   34,312    -    (12,784)
Interest accrued (37,979)   565    -    (37,414)
Deferred fuel costs 127,943    -    -    127,943 
Obligations under capital leases 22    -    -    22 
Pension and other postretirement liabilities (8,058)   108    -    (7,950)
System agreement cost equalization -    -    -    - 
Other 16,282    (4,549)   (55,567)   (43,834)
TOTAL (160,974)   (203,108)   (147,695)   (511,777)
               
NON-CURRENT LIABILITIES              
               
Accumulated deferred income taxes and taxes accrued 139,157    92,022    -    231,179 
Accumulated deferred investment tax credits (4,294)   -    -    (4,294)
Obligations under capital leases (48,836)   -    -    (48,836)
Other regulatory liabilities 3,596    -    -    3,596 
Decommissioning and retirement cost liabilities 17,583    22,008    -    39,591 
Accumulated provisions (5,054)   (2,686)   -    (7,740)
Pension and other postretirement liabilities (1,288)   (19,920)   -    (21,208)
Long-term debt (244,858)   (7,996)   -    (252,854)
Other (168,752)   53,848    19,200    (95,704)
TOTAL (312,746)   137,276    19,200    (156,270)
               
               
EQUITY              
               
Shareholders' Equity:              
Common stock, $.01 par value, authorized 500,000,000 shares;              
  issued 254,772,087 shares in 2009 and 248,174,087 shares in 2008 65    1    -    66 
Paid-in capital 480,642    18,767    1,734    501,143 
Retained earnings (114,355)   182,607    32,984    101,236 
Accumulated other comprehensive income (loss) (71)   52,677    -    52,606 
Less - treasury stock, at cost (8,763)   -    -    (8,763)
Total shareholders' equity 375,044    254,052    34,718    663,814 
Subsidiaries' preferred stock without sinking fund (1)    3    -    2 
TOTAL 375,043    254,055    34,718    663,816 
               
TOTAL LIABILITIES AND EQUITY $ (98,677)   $ 188,223    $ (93,777)   $ (4,231)
               
*Totals may not foot due to rounding.              
               

 

Entergy Corporation 
 
Consolidating Income Statement 
Three Months Ended March 31, 2009 
(Dollars in thousands) 
(Unaudited) 
 
    U.S. Utilities/ Parent & Other   Competitive Businesses   Eliminations   Consolidated
 
OPERATING REVENUES                
Electric   $ 2,028,156    $ -    $ (1,240)   $ 2,026,916 
Natural gas   74,049    -    -    74,049 
Competitive businesses   6,323    687,606    (5,782)   688,147 
     Total   2,108,528    687,606    (7,022)   2,789,112 
                 
OPERATING EXPENSES                
Operating and Maintenance:                
  Fuel, fuel related expenses, and gas purchased for resale   778,401    67,931    -    846,332 
  Purchased power   316,532    13,112    (6,389)   323,255 
  Nuclear refueling outage expenses   25,090    31,689    -    56,779 
  Other operation and maintenance   436,106    209,343    (747)   644,702 
Decommissioning   25,037    23,705    -    48,742 
Taxes other than income taxes   107,548    26,849    -    134,397 
Depreciation and amortization   222,319    35,533    -    257,852 
Other regulatory charges (credits) - net   (29,474)   -    -    (29,474)
     Total   1,881,559    408,162    (7,136)   2,282,585 
                 
OPERATING INCOME   226,969    279,444    114    506,527 
                 
OTHER INCOME (DEDUCTIONS)                
Allowance for equity funds used during construction   16,947    -    -    16,947 
Interest and dividend income   39,111    24,681    (33,142)   30,650 
Equity in earnings (loss) of unconsolidated equity affiliates   (52)   (3,075)   -    (3,127)
Miscellaneous - net   (5,083)   (4,975)   (114)   (10,172)
     Total   50,923    16,631    (33,256)   34,298 
                 
INTEREST AND OTHER CHARGES                
Interest on long-term debt   125,840    2,125    -    127,965 
Other interest - net   40,706    11,729    (33,142)   19,293 
Allowance for borrowed funds used during construction   (9,812)   -    -    (9,812)
     Total   156,734    13,854    (33,142)   137,446 
                 
INCOME BEFORE INCOME TAXES   121,158    282,221    -    403,379 
                 
Income taxes   56,788    106,258    -    163,046 
                 
CONSOLIDATED NET INCOME   64,370    175,963    -    240,333 
                 
Preferred dividend requirements of subsidiaries   4,333    665    -    4,998 
                 
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION   $ 60,037    $ 175,298    $ -    $ 235,335 
                 
EARNINGS PER AVERAGE COMMON SHARE:                
  BASIC   $0.31    $0.91        $1.22 
  DILUTED   $0.32    $0.88        $1.20 
                 
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:                
  BASIC               192,593,601 
  DILUTED               198,058,002 
                 
*Totals may not foot due to rounding.                
                 

 

Entergy Corporation 
 
Consolidating Income Statement 
Three Months Ended March 31, 2008 
(Dollars in thousands) 
(Unaudited) 
 
  U.S. Utilities/ Parent & Other   Competitive Businesses   Eliminations   Consolidated
 
OPERATING REVENUES                
Electric   $ 2,046,935    $ -    $ (708)   $ 2,046,227 
Natural gas   89,395    -    -    89,395 
Competitive businesses   6,007    729,278    (6,173)   729,112 
     Total   2,142,337    729,278    (6,881)   2,864,734 
                 
OPERATING EXPENSES                
Operating and Maintenance:                
  Fuel, fuel related expenses, and gas purchased for resale   454,583    85,918    -    540,501 
  Purchased power   611,851    15,412    (6,622)   620,642 
  Nuclear refueling outage expenses   19,337    31,922    -    51,258 
  Other operation and maintenance   419,934    191,707    (373)   611,268 
Decommissioning   23,325    22,671    -    45,996 
Taxes other than income taxes   85,786    22,785    -    108,571 
Depreciation and amortization   212,423    32,562    -    244,985 
Other regulatory charges (credits) - net   35,280    -    -    35,280 
     Total   1,862,519    402,977    (6,995)   2,258,501 
                 
OPERATING INCOME   279,818    326,301    114    606,233 
                 
OTHER INCOME (DEDUCTIONS)                
Allowance for equity funds used during construction   9,286    -    -    9,286 
Interest and dividend income   43,322    37,495    (26,535)   54,282 
Equity in earnings (loss) of unconsolidated equity affiliates   485    (1,414)   -    (929)
Miscellaneous - net   (6,047)   (5,395)   (114)   (11,556)
     Total   47,046    30,686    (26,649)   51,083 
                 
INTEREST AND OTHER CHARGES                
Interest on long-term debt   123,071    73    -    123,144 
Other interest - net   40,754    18,319    (26,535)   32,538 
Allowance for borrowed funds used during construction   (5,116)   -    -    (5,116)
     Total   158,709    18,392    (26,535)   150,566 
                 
INCOME BEFORE INCOME TAXES   168,155    338,595    -    506,750 
                 
Income taxes   68,527    124,476    -    193,003 
                 
CONSOLIDATED NET INCOME   99,628    214,119    -    313,747 
                 
Preferred dividend requirements of subsidiaries   4,332    665    -    4,998 
                 
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION   $ 95,296    $ 213,454    $ -    $ 308,749 
                 
EARNINGS PER AVERAGE COMMON SHARE:                
  BASIC   $0.49    $1.11        $1.60 
  DILUTED   $0.48    $1.08        $1.56 
                 
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:                
  BASIC               192,639,605 
  DILUTED               198,300,041 
                 
*Totals may not foot due to rounding.                
                 

 

Entergy Corporation 
 
Consolidating Income Statement 
Three Months Ended March 31, 2009 vs. 2008 
(Dollars in thousands) 
(Unaudited) 
 
  U.S. Utilities/ Parent & Other   Competitive Businesses   Eliminations   Consolidated
 
OPERATING REVENUES                
Electric   $ (18,779)   $ -    $ (532)   $ (19,311)
Natural gas   (15,346)   -    -    (15,346)
Competitive businesses   316    (41,672)   391    (40,965)
     Total   (33,809)   (41,672)   (141)   (75,622)
                 
OPERATING EXPENSES                
Operating and Maintenance:                
  Fuel, fuel related expenses, and gas purchased for resale   323,818    (17,987)   -    305,831 
  Purchased power   (295,319)   (2,300)   233    (297,387)
  Nuclear refueling outage expenses   5,753    (233)   -    5,521 
  Other operation and maintenance   16,172    17,636    (374)   33,434 
Decommissioning   1,712    1,034    -    2,746 
Taxes other than income taxes   21,762    4,064    -    25,826 
Depreciation and amortization   9,896    2,971    -    12,867 
Other regulatory charges (credits )- net   (64,754)   -    -    (64,754)
     Total   19,040    5,185    (141)   24,084 
                 
OPERATING INCOME   (52,849)   (46,857)   -    (99,706)
                 
OTHER INCOME (DEDUCTIONS)                
Allowance for equity funds used during construction   7,661    -    -    7,661 
Interest and dividend income   (4,211)   (12,814)   (6,607)   (23,632)
Equity in earnings (loss) of unconsolidated equity affiliates   (537)   (1,661)   -    (2,198)
Miscellaneous - net   964    420    -    1,384 
     Total   3,877    (14,055)   (6,607)   (16,785)
                 
INTEREST AND OTHER CHARGES                
Interest on long-term debt   2,769    2,052    -    4,821 
Other interest - net   (48)   (6,590)   (6,607)   (13,245)
Allowance for borrowed funds used during construction   (4,696)   -    -    (4,696)
     Total   (1,975)   (4,538)   (6,607)   (13,120)
                 
INCOME BEFORE INCOME TAXES   (46,997)   (56,374)   -    (103,371)
                 
Income taxes   (11,739)   (18,218)   -    (29,957)
                 
CONSOLIDATED NET INCOME   (35,258)   (38,156)   -    (73,414)
                 
Preferred dividend requirements of subsidiaries   -    -    -    - 
                 
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION   $ (35,258)   $ (38,156)   $ -    $ (73,414)
                 
EARNINGS PER AVERAGE COMMON SHARE:                
  BASIC   ($0.18)   ($0.20)       ($0.38)
  DILUTED   ($0.16)   ($0.20)       ($0.36)
                 
                 
*Totals may not foot due to rounding.                
                 

 

Entergy Corporation
 
Consolidating Income Statement 
Twelve Months Ended March 31, 2009 
(Dollars in thousands) 
(Unaudited) 
 
    U.S. Utilities/ Parent & Other   Competitive Businesses   Eliminations   Consolidated
 
OPERATING REVENUES                
Electric   $ 10,057,996    $ -    $ (4,147)   $ 10,053,849 
Natural gas   226,511    -    -    226,511 
Competitive businesses   29,327    2,729,410    (20,962)   2,737,775 
     Total   10,313,834    2,729,410    (25,109)   13,018,135 
                 
OPERATING EXPENSES                
Operating and Maintenance:                
  Fuel, fuel related expenses, and gas purchased for resale   3,536,222    347,373    -    3,883,595 
  Purchased power   2,162,423    54,707    (23,317)   2,193,813 
  Nuclear refueling outage expenses   97,974    129,305    -    227,279 
  Other operation and maintenance   1,945,953    832,492    (2,248)   2,776,197 
Decommissioning   97,533    94,623    -    192,156 
Taxes other than income taxes   427,439    95,340    -    522,779 
Depreciation and amortization   906,528    137,199    -    1,043,727 
Other regulatory charges (credits) - net   (4,871)   -    -    (4,871)
     Total   9,169,201    1,691,039    (25,565)   10,834,675 
                 
OPERATING INCOME   1,144,633    1,038,371    456    2,183,460 
                 
OTHER INCOME (DEDUCTIONS)                
Allowance for equity funds used during construction   52,183    -    -    52,183 
Interest and dividend income   152,083    92,219    (119,715)   124,587 
Equity in earnings (loss) of unconsolidated equity affiliates   (2,698)   (11,184)   -    (13,882)
Miscellaneous - net   (13,083)   3,156    (456)   (10,383)
     Total   188,485    84,191    (120,171)   152,505 
                 
INTEREST AND OTHER CHARGES                
Interest on long-term debt   502,450    3,270    -    505,720 
Other interest - net   176,327    63,434    (119,715)   120,046 
Allowance for borrowed funds used during construction   (29,962)   -    -    (29,962)
     Total   648,815    66,704    (119,715)   595,804 
                  
INCOME BEFORE INCOME TAXES   684,303    1,055,858    -    1,740,161 
                 
Income taxes   280,255    292,785    -    573,040 
                 
CONSOLIDATED NET INCOME   404,048    763,073    -    1,167,121 
                 
Preferred dividend requirements of subsidiaries   17,307    2,662    -    19,969 
                 
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION   $ 386,741    $ 760,411    $ -    $ 1,147,152 
                 
EARNINGS PER AVERAGE COMMON SHARE:                
  BASIC   $2.03    $4.00        $6.03 
  DILUTED   $2.05    $3.82        $5.87 
                 
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:                
  BASIC               190,387,963 
  DILUTED               199,282,466 
                 
*Totals may not foot due to rounding.                

 

Entergy Corporation 
 
Consolidating Income Statement 
Twelve Months Ended March 31, 2008 
(Dollars in thousands) 
(Unaudited)
 
  U.S. Utilities/ Parent & Other   Competitive Businesses   Eliminations   Consolidated
 
OPERATING REVENUES                
Electric   $ 8,983,790    $ -    $ (2,721)   $ 8,981,069 
Natural gas   210,516    -    -    210,516 
Competitive businesses   28,870    2,457,998    (23,380)   2,463,488 
     Total   9,223,176    2,457,998    (26,101)   11,655,073 
                 
OPERATING EXPENSES                
Operating and Maintenance:                
  Fuel, fuel related expenses, and gas purchased for resale   2,360,741    327,182    -    2,687,923 
  Purchased power   2,121,746    66,847    (25,239)   2,163,354 
  Nuclear refueling outage expenses   75,022    114,233    -    189,255 
  Other operation and maintenance   1,860,522    837,341    (1,318)   2,696,545 
Decommissioning   90,832    85,232    -    176,064 
Taxes other than income taxes   389,367    85,580    -    474,947 
Depreciation and amortization   855,664    120,622    -    976,286 
Other regulatory charges (credits) - net   66,694    -    -    66,694 
     Total   7,820,588    1,637,037    (26,557)   9,431,068 
                 
OPERATING INCOME   1,402,588    820,961    456    2,224,005 
                 
OTHER INCOME (DEDUCTIONS)                
Allowance for equity funds used during construction   34,770    -    -    34,770 
Interest and dividend income   175,114    144,532    (88,477)   231,169 
Equity in earnings (loss) of unconsolidated equity affiliates   1,112    (488)   -    624 
Miscellaneous - net   (13,213)   (17,428)   (456)   (31,097)
     Total   197,783    126,616    (88,933)   235,466 
                 
INTEREST AND OTHER CHARGES                
Interest on long-term debt   502,281    3,853    -    506,134 
Other interest - net   186,317    58,491    (88,491)   156,317 
Allowance for borrowed funds used during construction   (19,619)   -    -    (19,619)
     Total   668,979    62,344    (88,491)   642,832 
                 
INCOME BEFORE INCOME TAXES   931,392    885,233    14    1,816,639 
                 
Income taxes   364,044    197,310    -    561,354 
                 
CONSOLIDATED NET INCOME   567,348    687,923    14    1,255,285 
                 
Preferred dividend requirements of subsidiaries   20,651    3,217    14    23,882 
                 
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION   $ 546,697    $ 684,706    $ -    $ 1,231,403 
                 
                 
                 
EARNINGS PER AVERAGE COMMON SHARE:                
  BASIC   $2.81    $3.52        $6.33 
  DILUTED   $2.73    $3.41        $6.14 
                 
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:                
  BASIC               194,617,035 
  DILUTED               200,714,460 
                 
*Totals may not foot due to rounding.                
                 
                 

 

Entergy Corporation
 
Consolidating Income Statement 
Twelve Months Ended March 31, 2009 vs. 2008 
(Dollars in thousands) 
(Unaudited) 
 
  U.S. Utilities/ Parent & Other   Competitive Businesses   Eliminations   Consolidated
 
OPERATING REVENUES                
Electric   $ 1,074,206    $ -    $ (1,426)   $ 1,072,780 
Natural gas   15,995    -    -    15,995 
Competitive businesses   457    271,412    2,418    274,287 
     Total   1,090,658    271,412    992    1,363,062 
                 
OPERATING EXPENSES                
Operating and Maintenance:                
  Fuel, fuel related expenses, and gas purchased for resale   1,175,481    20,191    -    1,195,672 
  Purchased power   40,677    (12,140)   1,922    30,459 
  Nuclear refueling outage expenses   22,952    15,072    -    38,024 
  Other operation and maintenance   85,431    (4,849)   (930)   79,652 
Decommissioning   6,701    9,391    -    16,092 
Taxes other than income taxes   38,072    9,760    -    47,832 
Depreciation and amortization   50,864    16,577    -    67,441 
Other regulatory charges (credits )- net   (71,565)   -    -    (71,565)
     Total   1,348,613    54,002    992    1,403,607 
                 
OPERATING INCOME   (257,955)   217,410    -    (40,545)
                 
OTHER INCOME (DEDUCTIONS)                
Allowance for equity funds used during construction   17,413    -    -    17,413 
Interest and dividend income   (23,031)   (52,313)   (31,238)   (106,582)
Equity in earnings (loss) of unconsolidated equity affiliates   (3,810)   (10,696)   -    (14,506)
Miscellaneous - net   130    20,584    -    20,714 
     Total   (9,298)   (42,425)   (31,238)   (82,961)
                 
INTEREST AND OTHER CHARGES                
Interest on long-term debt   169    (583)   -    (414)
Other interest - net   (9,990)   4,943    (31,224)   (36,271)
Allowance for borrowed funds used during construction   (10,343)   -    -    (10,343)
     Total   (20,164)   4,360    (31,224)   (47,028)
                 
INCOME BEFORE INCOME TAXES   (247,089)   170,625    (14)   (76,478)
                 
Income taxes   (83,789)   95,475    -    11,686 
                 
CONSOLIDATED NET INCOME   (163,300)   75,150    (14)   (88,164)
                 
Preferred dividend requirements of subsidiaries   (3,344)   (555)   (14)   (3,913)
                 
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION   $ (159,956)   $ 75,705    $ -    $ (84,251)
                 
EARNINGS PER AVERAGE COMMON SHARE:                
  BASIC   ($0.78)   $0.48        ($0.30)
  DILUTED   ($0.68)   $0.41        ($0.27)
                 
                 
*Totals may not foot due to rounding.                
                 

 

Entergy Corporation
 
Consolidated Cash Flow Statement 
Three Months Ended March 31, 2009 vs. 2008 
(Dollars in thousands) 
(Unaudited) 
 
    2009   2008   Variance
             
OPERATING ACTIVITIES            
Consolidated net income   $240,333    $313,747    ($73,414)
Adjustments to reconcile consolidated net income to net cash flow            
provided by operating activities:            
  Reserve for regulatory adjustments   1,210    (2,909)   4,119 
  Other regulatory charges (credits) - net   (29,474)   35,280    (64,754)
  Depreciation, amortization, and decommissioning   306,595    290,981    15,614 
  Deferred income taxes, investment tax credits, and non-current taxes accrued   155,029    97,984    57,045 
  Equity in earnings of unconsolidated equity affiliates - net of dividends   3,127    929    2,198 
  Changes in working capital:            
    Receivables   102,428    (9,374)   111,802 
    Fuel inventory   (17,631)   (22,665)   5,034 
    Accounts payable   (134,008)   9,522    (143,530)
    Taxes accrued   (12,784)   -    (12,784)
    Interest accrued   (37,413)   (34,238)   (3,175)
    Deferred fuel   275,508    (195,650)   471,158 
    Other working capital accounts   (120,505)   (181,401)   60,896 
  Provision for estimated losses and reserves   1,281    4,034    (2,753)
  Changes in other regulatory assets   (447,882)   40,569    (488,451)
  Other   88,805    101,361    (12,556)
Net cash flow provided by operating activities   374,619    448,170    (73,551)
             
INVESTING ACTIVITIES            
Construction/capital expenditures   (455,737)   (373,317)   (82,420)
Allowance for equity funds used during construction   16,947    9,286    7,661 
Nuclear fuel purchases   (118,890)   (170,381)   51,491 
Proceeds from sale/leaseback of nuclear fuel   11,040    112,700    (101,660)
Payment for purchase of plant   -    (56,409)   56,409 
Changes in transition charge account   (7,831)   (8,352)   521 
NYPA value sharing payment   (72,000)   (72,000)   - 
Decrease (increase) in other investments   7,339    7,974    (635)
Proceeds from nuclear decommissioning trust fund sales   583,166    257,718    325,448 
Investment in nuclear decommissioning trust funds   (610,836)   (294,840)   (315,996)
Net cash flow used in investing activities   (646,802)   (587,621)   (59,181)
             
FINANCING ACTIVITIES            
Proceeds from the issuance of:            
  Long-term debt   489,987    545,000    (55,013)
  Common stock and treasury stock   927    4,670    (3,743)
Retirement of long-term debt   (215,023)   (438,227)   223,204 
Repurchase of common stock   -    (158,182)   158,182 
Changes in credit line borrowings - net   25,000    -    25,000 
Dividends paid:            
  Common stock   (142,085)   (144,579)   2,494 
  Preferred stock   (4,998)   (7,270)   2,272 
Net cash flow provided by (used in) financing activities   153,808    (198,588)   352,396 
             
Effect of exchange rates on cash and cash equivalents   842    17    825 
             
Net increase (decrease) in cash and cash equivalents   (117,533)   (338,022)   220,489 
             
Cash and cash equivalents at beginning of period   1,920,491    1,253,728    666,763 
             
Cash and cash equivalents at end of period   $1,802,958    $915,706    $887,252 
             
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:            
  Cash paid (received) during the period for:            
    Interest - net of amount capitalized   $176,892    $183,787    ($6,895)
    Income taxes   ($15,139)   $2,157    ($17,296)
             
  Noncash financing activities:            
    Long-term debt retired (equity unit notes)   ($500,000)   -    ($500,000)
    Common stock issued in settlement of equity unit purchase contracts   $500,000    -    $500,000 
             
             

 

Entergy Corporation 
 
Consolidated Cash Flow Statement 
Twelve Months Ended March 31, 2009 vs. 2008 
(Dollars in thousands) 
(Unaudited) 
 
    2009   2008   Variance
             
OPERATING ACTIVITIES            
Consolidated net income   $1,167,121    $1,255,285    ($88,164)
Adjustments to reconcile consolidated net income to net cash flow            
provided by operating activities:            
  Reserve for regulatory adjustments   (4,166)   (29,422)   25,256 
  Other regulatory charges (credits) - net   (4,871)   66,694    (71,565)
  Depreciation, amortization, and decommissioning   1,235,883    1,152,351    83,532 
  Deferred income taxes, investment tax credits, and non-current taxes accrued   390,993    189,901    201,092 
  Equity in earnings (loss) of unconsolidated equity affiliates - net of dividends   13,882    (624)   14,506 
  Changes in working capital:            
    Receivables   190,455    (138,162)   328,617 
    Fuel inventory   (2,527)   (33,304)   30,777 
    Accounts payable   (166,755)   188,721    (355,476)
    Taxes accrued   62,426    2,087    60,339 
    Interest accrued   (3,827)   (249)   (3,578)
    Deferred fuel   432,658    (348,798)   781,456 
    Other working capital accounts   (11,476)   (147,590)   136,114 
  Provision for estimated losses and reserves   9,709    (38,656)   48,365 
  Changes in other regulatory assets   (812,662)   126,519    (939,181)
  Changes in pensions and other postretirement liabilities   816,713    (94,070)   910,783 
  Other   (62,779)   363,939    (426,718)
Net cash flow provided by operating activities   3,250,777    2,514,622    736,155 
             
INVESTING ACTIVITIES            
Construction/capital expenditures   (2,294,675)   (1,648,780)   (645,895)
Allowance for equity funds used during construction   52,184    34,770    17,414 
Nuclear fuel purchases   (372,460)   (394,307)   21,847 
Proceeds from sale/leaseback of nuclear fuel   195,437    167,280    28,157 
Proceeds from sale of assets and businesses   30,725    400    30,325 
Payment for purchase of plant   (210,414)   (392,620)   182,206 
Changes in transition charge account   7,732    (27,625)   35,357 
NYPA value sharing payment   (72,000)   (72,000)   - 
Insurance proceeds received for property damages   130,114    83,104    47,010 
Decrease (increase) in other investments   (73,468)   (56,229)   (17,239)
Proceeds from nuclear decommissioning trust fund sales   1,977,725    1,681,295    296,430 
Investment in nuclear decommissioning trust funds   (2,020,177)   (1,814,068)   (206,109)
Net cash flow used in investing activities   (2,649,277)   (2,438,780)   (210,497)
             
FINANCING ACTIVITIES            
Proceeds from the issuance of:            
  Long-term debt   3,401,682    2,591,138    810,544 
  Preferred stock   -    10,000    (10,000)
  Common stock and treasury stock   31,032    52,611    (21,579)
Retirement of long-term debt   (2,263,602)   (1,473,299)   (790,303)
Repurchase of common stock   (354,169)   (815,574)   461,405 
Redemption of preferred stock   -    (55,577)   55,577 
Changes in credit line borrowings - net   55,000    -    55,000 
Dividends paid:            
  Common stock   (570,551)   (542,939)   (27,612)
  Preferred stock   (17,753)   (27,066)   9,313 
Net cash flow provided by (used in) financing activities   281,639    (260,706)   542,345 
             
Effect of exchange rates on cash and cash equivalents   4,113    58    4,055 
             
Net increase (decrease) in cash and cash equivalents   887,252    (184,806)   1,072,058 
             
Cash and cash equivalents at beginning of period   915,706    1,100,512    (184,806)
             
Cash and cash equivalents at end of period   $1,802,958    $915,706    $887,252 
             
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:            
  Cash paid (received) during the period for:            
    Interest - net of amount capitalized   $605,393    $641,071    ($35,678)
    Income taxes   $119,938    $347,532    ($227,594)
             
  Noncash investing and financing activities:            
    Long-term debt retired (equity unit notes)   ($500,000)   -    ($500,000)
    Common stock issued in settlement of equity unit purchase contracts   $500,000    -    $500,000